**Exhibit 99.1**

 

**ANNUAL INFORMATION FORM**

** **

**For the Fiscal Year Ended December 31, 2009**

 

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**ARC Energy Trust**

 

**2009 Annual Information Form**

 

**March 17, 2010**

 

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**TABLE OF CONTENTS**

** **
|                                                            |   | **Page** |
|-----------------------------------------------------------------|--------|----------|
|                                                            |   |     |
| GLOSSARY OF TERMS                                               |   | 1        |
| SPECIAL NOTES TO READER                                         |   | 2        |
| Regarding Forward Looking Statements and Risk Factors           |   | 2        |
| Access to Documents                                             |   | 3        |
| Abbreviations and Conversions                                   |   | 3        |
| OUR BUSINESS                                                    |   | 4        |
| Overview                                                        |   | 4        |
| Management Policies                                             |   | 4        |
| Distributions and Distribution Policy                           |   | 4        |
| Capital Expenditures                                            |   | 5        |
| Potential Acquisitions                                          |   | 5        |
| General Development of Our Business                             |   | 5        |
| Recent Developments                                             |   | 6        |
| Our Organizational Structure                                    |   | 6        |
| ARC ENERGY TRUST                                                |   | 6        |
| General                                                         |   | 6        |
| Federal Tax Changes for Income Trusts and Corporations          |   | 7        |
| STATEMENT OF RESERVES DATA AND  OTHER OIL AND GAS INFORMATION   |   | 8        |
| Disclosure of Reserves Data                                     |   | 8        |
| Reserves Data (Forecast Prices and Costs)                       |   | 9        |
| Definitions and Notes to Reserves Data Tables                   |   | 11       |
| Reserves Categories                                             |   | 11       |
| Levels of Certainty for Reported Reserves                       |   | 12       |
| Reconciliations of Changes in Reserves                          |   | 14       |
| Additional Information Relating to Reserves Data                |   | 15       |
| Other Oil and Gas Information                                   |   | 16       |
| Marketing Arrangements                                          |   | 23       |
| SHARE CAPITAL OF ARC RESOURCES                                  |   | 24       |
| Common Shares                                                   |   | 24       |
| Exchangeable Shares                                             |   | 24       |
| Second Preferred Shares                                         |   | 25       |
| OTHER INFORMATION RELATING TO OUR  BUSINESS                     |   | 26       |
| Borrowing                                                       |   | 26       |
| OUR INFORMATION                                                 |   | 26       |
| Trust Units                                                     |   | 26       |
| Special Voting Unit                                             |   | 26       |
| The Trust Indenture                                             |   | 27       |
| Trustee                                                         |   | 27       |
| Distributions and Allocations of Trust Income                   |   | 27       |
| Future Offerings                                                |   | 28       |
| Meetings and Voting                                             |   | 28       |
| Our Management                                                  |   | 28       |
| Limitation on Non-Resident Ownership                            |   | 28       |
| Right of Redemption                                             |   | 28       |
| Termination of the Trust                                        |   | 29       |
| Reporting to Unitholders                                        |   | 29       |
| Distribution Reinvestment and Optional Trust Unit Purchase Plan |   | 29       |
| CORPORATE GOVERNANCE                                            |   | 30       |
| General                                                         |   | 30       |
| Trust Indenture                                                 |   | 30       |

 

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| Decision Making                                                                              |   | 30 |
|----------------------------------------------------------------------------------------------|--------|----|
| Board of Directors of ARC Resources                                                          |   | 30 |
| AUDIT COMMITTEE DISCLOSURES                                                                  |   | 34 |
| Members of the Audit Committee                                                               |   | 34 |
| Principal Accountant Fees and Services                                                       |   | 35 |
| CONFLICTS OF INTEREST                                                                        |   | 35 |
| INTEREST OF MANAGEMENT AND OTHERS  IN MATERIAL TRANSACTIONS                                  |   | 36 |
| DISTRIBUTIONS TO UNITHOLDERS                                                                 |   | 36 |
| PRICE RANGE AND TRADING VOLUME OF  TRUST UNITS AND EXCHANGEABLE SHARES                       |   | 36 |
| INDUSTRY REGULATIONS                                                                         |   | 37 |
| Pricing and Marketing                                                                        |   | 37 |
| Pipeline Capacity                                                                            |   | 38 |
| The North American Free Trade Agreement                                                      |   | 38 |
| Royalties and Incentives                                                                     |   | 38 |
| Land Tenure                                                                                  |   | 43 |
| Environmental Regulation                                                                     |   | 44 |
| Climate Change Regulation                                                                    |   | 45 |
| RISK FACTORS                                                                                 |   | 47 |
| Risk Relating to Our Business and Operations                                                 |   | 48 |
| Risk Relating to Our Structure and Ownership of Trust Units                                  |   | 56 |
| Risk Factors Applicable to Residents of the United States  and Other Non-Residents of Canada |   | 57 |
| TRANSFER AGENTS AND REGISTRARS                                                               |   | 58 |
| MATERIAL CONTRACTS                                                                           |   | 58 |
| INTEREST OF EXPERTS                                                                          |   | 59 |
| ADDITIONAL INFORMATION                                                                       |   | 59 |

 
| APPENDIX A | - | REPORT ON RESERVES DATA BY  INDEPENDENT QUALIFIED RESERVES EVALUATOR       |
|------------|---|----------------------------------------------------------------------------|
| APPENDIX B | - | REPORT OF MANAGEMENT AND  DIRECTORS ON RESERVES DATA AND OTHER INFORMATION |
| APPENDIX C | - | MANDATE OF THE AUDIT  COMMITTEE                                            |

 

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**GLOSSARY OF TERMS**

** **

In thisAnnual Information Form, capitalized terms shall have the meanings set forthbelow:

 

**ARC**, **we**, **us**, **our**or **Trust** means ARC Energy Trustand all its controlled entities as a consolidated body;

 

**ARC Resources** means ARC Resources Ltd.;

 

**ARC Subco** means 1485275 Alberta Ltd., or such other corporationas may be substituted for ARC Subco;

 

**Exchangeable Shares** means the exchangeable shares of ARCResources that are exchangeable for Trust Units;

 

**Exchange Ratio**means the ratio at which the ExchangeableShares may be exchanged for Trust Units;

 

**GLJ** means GLJ Petroleum Consultants Ltd., independentpetroleum consultants of Calgary, Alberta;

 

**GLJ Report** means the report prepared by GLJ dated February 22,2010 evaluating the crude oil, natural gas, natural gas liquids and sulphurreserves attributable to the properties at December 31, 2009;

 

**Long Term Notes** means the unsecured long term notes issuedby ARC Resources to the Trust from time to time bearing interest at rates perannum ranging from 10.5 per cent to 13 per cent payable monthly with maturitydates of 15 years from the date of issuance;

 

**Montney West Area** means our lands west of the Dawson area innorth eastern British Columbia comprised of the Sunrise, Sundown, Sunset,Saturn and Monias areas;

 

**Royalties** means, collectively, the royalties payable by ARCResources to the Trust pursuant to the royalty agreements which equals 99 percent of royalty income;

 

**Tax Act** means the *IncomeTax Act* (Canada);

 

**Trust Indenture** means the trust indenture betweenComputershare Trust Company of Canada, as trustee, and ARC Resources Ltd., as amendedand restated as of May 15, 2006;

 

**Trust Units** means the units of the Trust, each unit representingan equal undivided beneficial interest in the Trust;

 

**TSX** means the Toronto Stock Exchange; and

 

**Unitholders** means holders of Trust Units of the Trust.

 

Certainother terms used in this Annual Information Form but not defined hereinare defined in NI 51-101 and, unless the context otherwise requires, shall havethe same meanings herein as in NI 51-101.

 

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**SPECIAL NOTES TO READER**

** **

**RegardingForward Looking Statements and Risk Factors**

** **

Certainstatements contained in this Annual Information Form, and in certain documentsincorporated by reference into this Annual Information Form, constituteforward-looking statements.  Thesestatements relate to future events or our future performance.  All statements other than statements ofhistorical fact may be forward-looking statements.  Forward-looking statements are often, but notalways, identified by the use of words such as “seek”, “anticipate”, “budget”,“plan”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”,“predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”,“believe” and similar expressions.  Inaddition there are forward looking statements in this Annual Information Form underthe headings: “ARC Energy Trust — Federal Tax Changes for Income Trusts andCorporations” as to our anticipated conversion to a corporation and related taxmatters; “Statement of Reserves Data and Other Oil and Gas Information” as toour reserves and future net revenues from our reserves, pricing and inflationrates and future development costs; “Statement of Reserves Data and Other Oiland Gas Information - Additional Information Relating to Reserves Data” as tothe development of our proved undeveloped reserves and probable undevelopedreserves; and “Statement of Reserves Data and Other Oil and Gas Information -Other Oil and Gas Information” as to our future development activities, thestatus of our enhanced recovery projects, hedging policies, reclamation andabandonment obligation, tax horizon, exploration and development activities andproduction estimates.  These statementsinvolve known and unknown risks, uncertainties and other factors that may causeactual results or events to differ materially from those anticipated in suchforward-looking statements.  We believethe expectations reflected in those forward-looking statements are reasonablebut no assurance can be given that these expectations will prove to be correctand such forward-looking statements included in, or incorporated by referenceinto, this Annual Information Form should not be unduly relied upon.  These statements speak only as of the date ofthis Annual Information Form or as of the date specified in the documentsincorporated by reference into this Annual Information Form, as the case maybe.

 

Inaddition to the forward looking statements identified above, this AnnualInformation Form, and the documents incorporated by reference, containforward-looking statements pertaining to the performance characteristics of ouroil and natural gas properties; oil and natural gas production levels; the sizeof the oil and natural gas reserves; projections of market prices and costs;expectations regarding the ability to raise capital and to continually add toreserves through acquisitions and development; treatment under governmentalregulatory regimes and tax laws; and capital expenditures programs.

 

**Actual results achieved during the forecast period will varyfrom the information provided herein as a result of numerous known and unknownrisks and uncertainties and other factors. In addition, these risks and uncertainties are material factorsaffecting the success of our business.** Such factors include, but are not limited to: declines in oil andnatural gas prices; variations in interest rates and foreign exchange rates;uncertainties relating to the weakened global economy and consequentialrestricted access to capital, stock market volatility, market valuations andincreased borrowing costs; refinancing risk for existing debt and debt servicecosts; access to external sources of capital; risks associated with our hedgingactivities; third party credit risk; risks associated with the exploitation ofour properties and our ability to acquire reserves; government regulation andcontrol and changes in governmental legislation; changes in income tax laws,royalty rates and other incentive programs; uncertainties associated withestimating oil and natural gas reserves; risks associated with our conversionto a corporate structure; risks associated with acquiring, developing andexploring for natural gas and other aspects of our operations; the timing ofpayment of distributions, if any; certain of our enhanced recovery projects arenot currently economically feasible;****risksassociated with large projects or expansion of our activities; the failure torealize anticipated benefits of acquisitions and dispositions or to managegrowth; risks associated with residency restrictions in the ownership of ourTrust Units; changes in climate change laws and other environmentalregulations; competition in the oil and gas industry for, among other things,acquisitions of reserves, undeveloped lands, skilled personnel and drilling andrelated equipment; risks of non-cash losses as a result of the application ofaccounting policies;****our operatingactivities and ability to retain key personnel; depletion of our reserves;risks associated with securing and maintaining title to our properties; risksassociated with our structure and ownership of Trust Units; risks for UnitedStates and other non-resident Unitholders and other factors, many of which arebeyond our control.

 

Theactual results could differ materially from those results anticipated in theseforward-looking statements, which are based on assumptions, including as to themarket prices for oil and natural gas; the continuation of the present policiesof the Board of Directors of ARC Resources relating to management of ARC, anddistributions, capital expenditures and other matters; the continuedavailability of capital, acquisitions of reserves, undeveloped lands and 

 

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skilledpersonnel; the continuation of the current tax and regulatory regime and otherassumptions contained in this Annual Information Form.

 

Statementsrelating to “reserves” are deemed to be forward-looking statements, as theyinvolve the implied assessment, based on certain estimates and assumptions thatthe reserves described can be profitably produced in the future.

 

Readersare cautioned that the foregoing lists of factors are not exhaustive.  The forward-looking statements contained inthis Annual Information Form and the documents incorporated by referenceherein are expressly qualified by this cautionary statement.  We do not undertake any obligation topublicly update or revise any forward-looking statements except as required bysecurities laws or regulations.

 

**Access toDocuments**

** **

Anydocument referred to in this Annual Information Form and described asbeing filed on SEDAR at www.sedar.com (including those documents referred to asbeing incorporated by reference in this Annual Information Form) may beobtained free of charge from us at 2100, 440 — 2nd Avenue S.W.,Calgary, Alberta, T2P 5E9.

 

**Abbreviationsand Conversions**

 
| bbl    | Barrel                                                                                                                                     |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------|
| bbl/d  | barrels per day                                                                                                                            |
| Bcf    | billion cubic feet                                                                                                                         |
| boe    | barrels of oil equivalent converting 6 Mcf of  natural gas or one barrel of natural gas liquids to one barrel of oil  equivalent |
| boe/d  | barrels of oil equivalent per day                                                                                                     |
| Mbbl   | one thousand barrels                                                                                                                       |
| mboe   | one thousand barrels of oil equivalent                                                                                                     |
| Mcf    | one thousand cubic feet                                                                                                                    |
| Mcfpd  | one thousand cubic feet per day                                                                                                            |
| MMBTU  | one million British Thermal Units                                                                                                          |
| MMcf   | one million cubic feet                                                                                                                     |
| MMcfpd | one million cubic feet per day                                                                                                             |
| $MM    | one million dollars                                                                                                                        |
| MMbbl  | one million barrels                                                                                                                        |
| NGLs   | natural gas liquids                                                                                                                        |
| Tcf    | one trillion cubic feet                                                                                                                    |

 

We haveadopted the standard of 6 Mcf:1boe when converting natural gas to boes.  Boes may be misleading, particularly if usedin isolation.  A boe conversion ratio of6 Mcf per barrel is based on an energy equivalency conversion method primarilyapplicable at the burner tip and does not represent a value equivalency at thewellhead.

 

Thefollowing table sets forth certain standard conversions between StandardImperial Units and the International System of Units (or metric units).

 
| **To Convert From** | ** ** | **To**       | ** ** | **Multiply By** | ** ** |
|---------------------|------------|--------------|------------|-----------------|------------|
| cubic metres        |       | cubic feet   |       | 35.315          |       |
| bbls                |       | cubic metres |       | 0.159           |       |
| cubic metres        |       | bbls         |       | 6.290           |       |
| Feet                |       | metres       |       | 0.305           |       |
| Metres              |       | feet         |       | 3.281           |       |
| Miles               |       | kilometres   |       | 1.609           |       |
| Kilometres          |       | miles        |       | 0.621           |       |
| Acres               |       | hectares     |       | 0.4047          |       |
| Hectares            |       | acres        |       | 2.471           |       |

 

Alldollar amounts set forth in this Annual Information Form are in Canadiandollars, except where otherwise indicated.

 

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**OUR BUSINESS**

** **

**Overview**

** **

ARCEnergy Trust (“ARC” or “the Trust”), is located in Calgary, Alberta and is oneof Canada’s largest conventional oil and gas companies.  Currently structured as a trust, ARC developsand acquires long-life, low declining oil and gas properties in westernCanada.  ARC’s Unitholders receive amonthly cash distribution from our producing oil and gas assets owned by ARCResources Ltd.  ARC plans to convert to adividend-paying corporation on January 1, 2011.

 

Oursubsidiaries, trusts and partnerships are entitled to carry on a wide scope ofenergy related activities including the business of acquiring, developing,exploiting and disposing of all types of energy business related assets, whichincludes petroleum and natural gas related assets, oil sands interests,electricity or power generating assets and pipeline, gathering, processing andtransportation assets.  To date theTrust’s business has been focused on the acquisition and development of oil andnatural gas reserves in western Canada. We issue Trust Units and may also issue securities of ARC Resources oran affiliate of ARC Resources which are exchangeable for Trust Units and confervoting rights in us.

 

Theprincipal offices of the Trust and ARC Resources are located at 2100, 440 — 2nd Avenue S.W., Calgary, Alberta, T2P 5E9 and itsregistered office is located at 1400, 350 — 4th Avenue S.W.,Calgary, Alberta, T2P 3N9.

 

**ManagementPolicies**

** **

All ouractivities are directed towards maximizing value creation for Unitholders. Thisis achieved through a combination of investing capital to enhance the value ofour assets, operating our producing oil and gas properties in a low cost mannerto maximize the recovery of reserves, and through making monthly distributionsto our Unitholders.  We direct ourefforts to increase the value of our assets through development drilling andassociated development activities and enhanced oil recovery activities as wellas by the periodic acquisition of undeveloped and producing oil and gasproperties.  We acquire oil and naturalgas producing properties and primarily participate in development activitiesthat are generally considered to be of a low risk nature in the oil and gas industry.  Also, a percentage of each year’s capitalbudget will be devoted to moderate risk development and lower risk explorationopportunities on our properties.  Recently, we have undertaken a moresubstantial program of purchasing undeveloped land, particularly in the Dawsonand Montney West area of north-eastern British Columbia, where we have spentapproximately $229 million since January 1, 2006.

 

We havepolicies for the hiring, training and development of staff to provide the inhouse expertise to fully exploit ARC’s assets. In addition, we have specific health and safety policies which set outprocedures, practices and reporting of actions to assist in ensuring that ARCemployees and contractors employ safety measures and act in a safe and prudentmanner.  We also have policies which encompassthe cleanup, abandonment and site reclamation activities of ARC.

 

**Distributionsand Distribution Policy**

** **

Distributionsare made on the 15th day (or if such date is not a business day, onthe next business day) following the end of each calendar month to Unitholdersof record on the last business day of each such calendar month.

 

TheBoard of Directors of ARC Resources on behalf of the Trust reviews thedistribution policy from time to time. The actual amount distributed is at the discretion of the Board ofDirectors and is principally dependent upon the commodity price environment andthe amount of cash flow from operating activities utilized to fund the Trust’scapital expenditure program and the annual contribution to the Trust’sreclamation fund.  In times of highcommodity prices, we withhold a greater percentage of cash flow from operatingactivities so that more of the capital program can be funded internally.

 

Historically,ARC has strived for stability in distributions and has announced distributionlevels on a quarterly basis.  Duringtimes of extreme commodity price volatility, such as those we are experiencedover the past 24 months, the distributions are reviewed on a monthly basis andadjusted as required.

 

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**CapitalExpenditures**

** **

We mayapprove future capital expenditures or farmouts under the terms of the royaltyagreement.  Future capital expenditureson the properties will generally be of the type that are****intended to maintain or improve productionfrom the properties.  We may financecapital expenditures from production revenues, the proceeds of the issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, borrowings, farmouts or with working capital.

 

We mayacquire additional properties and related tangible equipment and fund suchacquisitions from production revenues, the net proceeds of any issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, or from borrowings, farmouts or with workingcapital.  We may sell any of ourinterests in properties and release the Royalties from such properties inconsideration of the allocation of a portion of the proceeds to the Trust.  In connection with the sale of any interestsin the properties, we will determine whether the net proceeds of the saleshould be reinvested in additional properties, used to repay borrowings or makecapital expenditures in ARC Resources or be distributed to Unitholders.

 

**PotentialAcquisitions**

** **

Wecontinue to evaluate potential acquisitions of all types of petroleum andnatural gas and other energy-related assets as part of our ongoing acquisitionprogram.  We are normally in the processof evaluating several potential acquisitions at any one time which individuallyor together could be material.  We cannotpredict whether any current or future opportunities will result in one or moreacquisitions.

 

**GeneralDevelopment of Our Business**

** **

Adescription of the general development of our business over the last threefinancial years follows.

 

In2007, we incurred capital expenditures of $439.7 million, of which $281.4million (64 per cent) was development and facility capital expenditures, $42.5million (10 per cent) was property acquisitions costs net of dispositions and$112.5 million (26 per cent) was costs of lands acquired, geological andgeophysical, and drilling costs for 2007 exploration wells drilled.  Included in these costs was the purchase ofundeveloped land located primarily in the Dawson and Montney West Area ofBritish Columbia through Crown mineral sales for $77.5 million.  We also distributed $498 million toUnitholders in 2007.

 

In2008, we incurred capital expenditures of $599.6 million, of which $371.1million (62 per cent) was development and facility capital expenditures, $51million (nine per cent) was property acquisitions costs net of dispositions and$164.1 million (27 per cent) was costs of lands acquired, geological andgeophysical, and drilling costs for 2008 exploration wells drilled.  Included in these costs was the purchase ofundeveloped acreage through Crown mineral sales for $122.4 million, of which$80.3 million was expended in the Dawson and Montney West Area of BritishColumbia.  We also distributed $570million to Unitholders in 2008.

 

In 2009, we incurred capitalexpenditures of $518 million, of which $326.3 million (63 per cent) wasdevelopment and facility capital expenditures and $17.4 million (three percent) was costs of lands acquired, geological and geophysical, and drillingcosts for 2009 exploration wells drilled. We completed net property dispositions of $20.5 million and we completedone corporate acquisition for total consideration of $178.9 million (resultingin total acquisitions, net of dispositions, of $158.4 million in theyear).  We also distributed $299 millionto Unitholders in 2009.

 

Pursuant to the corporateacquisition, we acquired an average 75 percent working interest in 26,000 grossacres of developed lands which include 38 net oil wells and 24 net gas wells, a30 percent interest in our gas plant located at 10-36-66-25 W5M (which willbring the interest of ARC Resources in such plant to 100 percent) and 121,000gross (106,000 net) acres of undeveloped lands. Oil production from these assets is processed through three facilities,all of which are operated by us, while gas production from these assets isprocessed through two facilities currently operated by third parties.  We anticipate that we will operate nearly allof the production from these assets. Production from these assets for the nine months ended September 30,2009 was approximately 2,000 boe/d and was weighted approximately 75 percent tonatural gas and approximately 25 percent to crude oil and natural gas liquids.

 

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On February 6, 2009, the Trust closed an equity offering to issue15.5 million Trust Units at $16.35 per unit. The net proceeds of the transaction were $240 million and were used toreduce our bank indebtedness.

 

**RecentDevelopments**

** **

On January 5, 2010, the Trust closedan equity offering to issue 13 million Trust Units at $19.40 per unit.  The net proceeds of the offering were $239.5million and were used to reduce our bank indebtedness.

 

**OurOrganizational Structure**

** **

Our structure and the flow of cash from ARCResources to the Trust as of December 31, 2009 are set forth below:

 

 

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Notes:

(1)                                As at December 31, 2009,properties in British Columbia are held by ARC Petroleum Inc. as trustee andagent of ARC Resources.

(2)                                ARC Resources had a total of870,841 Exchangeable Shares outstanding as at December 31, 2009 that wereexchangeable for approximately 2,368,278 Trust Units.

 

**ARC ENERGY TRUST**

** **

**General**

** **

We are an open-end investment trust createdon May 7, 1996 under the laws of the Province of Alberta pursuant to theTrust Indenture.  Computershare TrustCompany of Canada has been appointed as trustee under the Trust Indenture.  The beneficiaries of the Trust are holders ofthe Trust Units.  The principal and headoffice of the Trustee

 

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is located at Suite 600, 530 8th Avenue SW., Calgary, Alberta,T2P 3S8.  The Trust Indenture hasbeen amended from time to time, the latest amendments being approved at theannual and special meeting of Unitholders held on May 15, 2006.

 

The following are the names, the percentageof voting securities and the jurisdiction governing our material****subsidiaries and trusts, either direct orindirect, as at December 31, 2009:

 
| ** **         | ** ** | **Percentage of voting  securities  (directly or indirectly)** | ** ** | **Nature of Entity** | ** ** | **Jurisdiction of  Incorporation/  Formation** | ** ** |
|--------------------|------------|----------------------------------------------------------------|------------|----------------------|------------|------------------------------------------------|------------|
| ARC Resources Ltd. |       | 100                                                            | %          | Corporation          |       | Alberta                                        |       |

 

Our principal undertaking is to receiveRoyalties and other income on petroleum and natural gas properties and relatedassets and to acquire and hold securities of subsidiaries, trusts andpartnerships.  Our principal investmentsare the Royalties granted by ARC Resources, the common shares of ARC Resourcesand the Long Term Notes.  The Royaltiesconsist of a 99 per cent share of royalty income on all of the properties heldby ARC Resources.  Royalty income isgenerally all production revenue less all operating and capital costs and alldebt service charges including principal repayments.  On each monthly distribution date, ARCResources pays the Trust 99 per cent of royalty income and ARC Resources paysinterest on outstanding Long Term Notes. The Trust will make distributions of such funds, subject only to therequired deductions and its expenses. Such distributions may be wholly or in part taxable.  See “Distributions to Unitholders”.

 

We are structured with the objective ofhaving income tax incurred only in the hands of Unitholders.  Income distributed to Unitholders consistsessentially of cash flow from operating activities generated by our oil andnatural gas properties.  Morespecifically, internally generated cash flow from operating activities, withthe exception of such cash flow used for capital expenditures, reclamation fundcontributions, interest expense, debt repayments, income taxes not passed on toUnitholders, and working capital requirements, is effectively returned toUnitholders.

 

As an open-ended investment, Unitholdershave a right to redeem their Trust Units. As with most other open-ended funds, it is anticipated that trading onthe TSX and not the right of retraction would continue as the primary mechanismfor Unitholders to sell their Trust Units. For more detailed information regarding the right of redemption, see“Our Information - Right of Redemption”.

 

As at December 31, 2009, we hadapproximately 514 employees and full time consultants.

 

**Federal TaxChanges for Income Trusts and Corporations**

** **

On June 22, 2007, the federallegislation (Bill C-52) implementing the tax on publicly traded income trustsand limited partnerships (the “**SIFT Rules**”)received Royal Assent.  The SIFT Rules arenot expected to effect the Trust until 2011 provided the Trust does not exceedthe normal growth guidelines announced by the Department of Finance.  Subsequent to the January 5, 2010 equityissuance, the Trust can increase its equity by approximately $4.8 billionbefore 2011 without exceeding the normal growth guidelines. The Trust does notanticipate that the normal growth guidelines will impair the Trust’s ability toannually replace or grow reserves in the next year as the guidelines allowsufficient growth targets.

 

Under the SIFT Rules, the SIFT tax ratewill be the federal general corporate income tax rate and the applicableprovincial corporate rate. The federal general corporate income tax rate willbe 16.5 per cent in 2011 and 15 per cent after 2011 and the provincialcomponent will be 10 per cent.

 

The tax legislation for the conversion ofpublicly traded income trusts into taxable Canadian corporations on a taxdeferred basis received royal assent on March 12, 2009.

 

Management and the Board of Directorscontinue to work on the plan for converting our Trust to a corporation on January 1,2011.  After the conversion, thecorporation would expect to allocate its cash flow among funding a portion ofcapital expenditures, periodic debt repayments, site reclamation expenditures,and cash payments to

 

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shareholders in the form of dividends.   Current taxes payable by us after convertingto a corporation will be subject to normal corporate tax rates.  Taxable income as a corporation will varydepending on total income and expenses and vary with changes to commodityprices, costs, claims for both accumulated tax pools and tax pools associatedwith current year expenditures.  As wehave $2.2 billion of income tax pools, it is expected that taxable income willbe reduced or potentially eliminated for the initial approximate two yearperiod post conversion.

 

Returns to shareholders after conversion toa corporation will be impacted by the reduction of cash flow required to paycurrent income taxes, if any.  Over thelonger term, we would expect Canadian investors who hold their Trust Units in ataxable account to be relatively indifferent on an after tax basis as towhether ARC is structured as a corporation or as a trust in 2011.  However, Canadian tax deferred investors(those holding their trust units in a tax deferred vehicle such as an RRSP,RRIF or pension plan) and foreign investors will realize a lower after taxreturn on distributions in taxable years after 2011 due to the introduction ofthe SIFT Tax should ARC stay as a trust, and their inability to claim thedividend tax credit if ARC converts to a corporation.

 

If a conversion from the trust structure toa corporation is approved by the Unitholders, the income tax payable will varyand Unitholders should consult their tax advisors for details on the directimpact to themselves.

 

**STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION**

** **

The statement of reserves data and otheroil and gas information is set forth below (the “**Statement**”).  Theeffective date of the Statement is December 31, 2009 and the preparationdate of the Statement is January 18, 2010. The Report of Management and Directors on Reserves Data and OtherInformation on Form 51-101F3 and the Report on Reserves Data by GLJ on Form 51-102F2are attached as Appendices A and B to this Annual Information Form.

 

**Disclosure ofReserves Data**

** **

The reserves data set forth below is basedupon an evaluation by GLJ with an effective date of December 31, 2009contained in the GLJ Report dated February 22, 2010.  The reserves data summarizes our oil, liquidsand natural gas reserves and the net present values of future net revenue forthese reserves using forecast prices and costs prior to provision for interest,general and administrative expenses, the impact of any hedging activities orthe liability associated with certain abandonment and well, pipeline andfacilities reclamation costs which were not deducted by GLJ in estimatingfuture net revenue.  Future net revenueshave been presented on a before and after tax basis.  The reserves data conforms with therequirements of NI 51-101.  We engagedGLJ to provide an evaluation of proved and proved plus probable reserves.  See also “Definitions and Notes to ReservesData Tables” below.

 

All of our reserves are in Canada and,specifically, in the provinces of Alberta, British Columbia, Saskatchewan andManitoba.

 

**It should not be assumedthat the estimates of future net revenues presented in the tables belowrepresent the fair market value of the reserves.  There is no assurance that the forecastprices and costs assumptions will be attained and variances could bematerial.  The recovery and reservesestimates of crude oil, natural gas liquids and natural gas reserves providedherein are estimates only and there is no guarantee that the estimated reserveswill be recovered.  Actual crude oil, naturalgas and natural gas liquid reserves may be greater than or less than theestimates provided herein.  Readersshould review the definitions and information contained in “Definitions andNotes to Reserves Data Tables” in conjunction with the following tables andnotes.  For more information as to therisks involved, see “Risk Factors —Risks Relating to Our Business andOperations”.**

 

8

----

 

**Reserves Data(Forecast Prices and Costs)**

** **

SUMMARYOF OIL AND GAS RESERVESAND NET PRESENT VALUES OF FUTURE NET REVENUEas of December 31, 2009FORECAST PRICES AND COSTS

 
| ** **                  | ** ** | **RESERVES**              | ** ** |
|-----------------------------|------------|---------------------------|------------|
| ** **                  | ** ** | **LIGHT  AND MEDIUM OIL** | ** ** | **HEAVY  OIL** | ** ** |
| **RESERVES  CATEGORY**      | ** ** | **Gross  (Mbbl)**         | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                      |       |   |   |   |   |   |   |
| PROVED                      |       |                      |       |   |   |   |   |   |   |
| Developed  Producing        |       | 92,989                    |       | 79,083 |   | 2,199 |   | 2,157 |   |
| Developed  Non-Producing    |       | 1,112                     |       | 921 |   | 13 |   | 12 |   |
| Undeveloped                 |       | 8,655                     |       | 7,151 |   | 0 |   | 0 |   |
| TOTAL PROVED                |       | 102,756                   |       | 87,154 |   | 2,212 |   | 2,168 |   |
|                        |       |                      |       |   |   |   |   |   |   |
| PROBABLE                    |       | 31,607                    |       | 25,765 |   | 622 |   | 577 |   |
|                        |       |                      |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 134,363                   |       | 112,919 |   | 2,834 |   | 2,745 |   |

 
| ** **                  | ** ** | **RESERVES**     | ** ** |
|-----------------------------|------------|------------------|------------|
| ** **                  | ** ** | **NATURAL  GAS** | ** ** | **NATURAL  GAS LIQUIDS** | ** ** |
| **RESERVES  CATEGORY**      | ** ** | **Gross  (Bcf)** | ** ** | **Net  (Bcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |             |       |   |   |   |   |   |   |
| PROVED                      |       |             |       |   |   |   |   |   |   |
| Developed  Producing        |       | 481              |       | 419 |   | 8,299 |   | 5,857 |   |
| Developed  Non-Producing    |       | 38               |       | 30 |   | 420 |   | 297 |   |
| Undeveloped                 |       | 388              |       | 320 |   | 2,636 |   | 2,062 |   |
| TOTAL PROVED                |       | 907              |       | 769 |   | 11,355 |   | 8,216 |   |
|                        |       |             |       |   |   |   |   |   |   |
| PROBABLE                    |       | 435              |       | 355 |   | 4,281 |   | 3,183 |   |
|                        |       |             |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 1,342            |       | 1,124 |   | 15,637 |   | 11,399 |   |

 
| ** **                  | ** ** | **RESERVES**      | ** ** |
|-----------------------------|------------|-------------------|------------|
| ** **                  | ** ** | **TOTAL**         | ** ** |
| **RESERVES  CATEGORY**      | ** ** | **Gross  (mboe)** | ** ** | **Net  (mboe)** | ** ** |
|                        |       |              |       |   |   |
| PROVED                      |       |              |       |   |   |
| Developed  Producing        |       | 183,663           |       | 156,959 |   |
| Developed  Non-Producing    |       | 7,862             |       | 6,194 |   |
| Undeveloped                 |       | 76,018            |       | 62,525 |   |
| TOTAL PROVED                |       | 267,543           |       | 225,678 |   |
|                        |       |              |       |   |   |
| PROBABLE                    |       | 109,000           |       | 88,672 |   |
|                        |       |              |       |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 376,543           |       | 314,350 |   |

 

9

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| ** **                  | ** ** | **NET PRESENT VALUES OF FUTURE NET REVENUE**   | ** ** |
|-----------------------------|------------|------------------------------------------------|------------|
| ** **                  | ** ** | **BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | ** ** | **AFTER INCOME TAXES DISCOUNTED AT (%/year)** | ** ** |
| **RESERVES  CATEGORY**      | ** ** | **0  (MM$)**                                   | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** | **0  (MM$)** | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** |
|                        |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROVED                      |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed  Producing        |       | 7,164                                          |       | 4,755 |   | 3,618 |   | 2,956 |   | 2,520 |   | 6,023 |   | 4,095 |   | 3,173 |   | 2,629 |   | 2,267 |   |
| Developed  Non-Producing    |       | 230                                            |       | 157 |   | 119 |   | 96 |   | 80 |   | 177 |   | 121 |   | 92 |   | 74 |   | 62 |   |
| Undeveloped                 |       | 1,889                                          |       | 1,219 |   | 847 |   | 615 |   | 458 |   | 1,416 |   | 891 |   | 598 |   | 415 |   | 291 |   |
| TOTAL  PROVED               |       | 9,283                                          |       | 6,130 |   | 4,584 |   | 3,666 |   | 3,058 |   | 7,616 |   | 5,107 |   | 3,863 |   | 3,118 |   | 2,621 |   |
|                        |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROBABLE                    |       | 4,285                                          |       | 2,072 |   | 1,222 |   | 806 |   | 569 |   | 3,220 |   | 1,548 |   | 903 |   | 588 |   | 409 |   |
|                        |       |                                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| TOTAL  PROVED PLUS PROBABLE |       | 13,568                                         |       | 8,202 |   | 5,805 |   | 4,472 |   | 3,627 |   | 10,836 |   | 6,655 |   | 4,766 |   | 3,706 |   | 3,030 |   |

 

TOTALFUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2009FORECAST PRICES AND COSTS

 
| **RESERVES  CATEGORY**        | ** ** | **REVENUE  (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **ABANDONMENT  AND  RECLAMATION  COSTS  (MM$)** | ** ** | **FUTURE  NET  REVENUE  BEFORE  INCOME  TAXES  (MM$)** | ** ** | **INCOME  TAXES  (MM$)** | ** ** | **FUTURE  NET  REVENUE  AFTER  INCOME  TAXES  (MM$)** | ** ** |
|-------------------------------|------------|--------------------|------------|----------------------|------------|-----------------------------|------------|-------------------------------|------------|-------------------------------------------------|------------|--------------------------------------------------------|------------|--------------------------|------------|-------------------------------------------------------|------------|
|                          |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Reserves               |       | 19,123             |       | 3,184                |       | 5,344                       |       | 1,060                         |       | 251                                             |       | 9,283                                                  |       | 1,667                    |       | 7,616                                                 |       |
|                          |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Plus Probable Reserves |       | 27,468             |       | 4,779                |       | 7,221                       |       | 1,612                         |       | 287                                             |       | 13,568                                                 |       | 2,732                    |       | 10,836                                                |       |

 

FUTURENET REVENUEBY PRODUCTION GROUPas of December 31, 2009FORECAST PRICES AND COSTS

 
| **RESERVES  CATEGORY**         | ** ** | **PRODUCTION  GROUP(1)(2)** | ** ** | **FUTURE  NET  REVENUE  BEFORE  INCOME TAXES  (discounted at  10%/year)  (MM$)** | ** ** | **PER  UNIT(3)** | ** ** |
|--------------------------------|------------|-----------------------------|------------|----------------------------------------------------------------------------------|------------|------------------|------------|
|                           |       |                        |       |                                                                             |       |             |       |
| Proved Reserves                |       | Light and  Medium Crude Oil |       | 2,461                                                                            |       | $                | 25.64/boe  |   |
|                           |       | Heavy Oil                   |       | 68                                                                               |       | $                | 29.61/boe  |   |
|                           |       | Natural Gas                 |       | 2,055                                                                            |       | $                | 2.69/Mcf   |   |
|                           |       | Total                       |       | 4,584                                                                            |       |             |       |
|                           |       |                        |       |                                                                             |       |             |       |
| Proved Plus  Probable Reserves |       | Light and  Medium Crude Oil |       | 2,997                                                                            |       | $                | 23.97/boe  |   |
|                           |       | Heavy Oil                   |       | 80                                                                               |       | $                | 27.80/boe  |   |
|                           |       | Natural Gas                 |       | 2,728                                                                            |       | $                | 2.44/Mcf   |   |
|                           |       | Total                       |       | 5,805                                                                            |       |             |       |

 

----

Notes:

(1)                                  Including solution gas andother by-products.

(2)                                  Including by-products butexcluding solution gas.

(3)                                  Unit values are based onCompany Net Reserves.

 

10

----

 

**Definitions and Notes to Reserves DataTables**

** **

In the tablesset forth above in “Disclosure of Reserves Data” and elsewhere in this AnnualInformation Form the following definitions and other notes are applicable:

 

1.                                       “**Gross**” means:

 

(a)                                  in relation to our interest inproduction and reserves, our interest (operating and non-operating) beforededuction of royalties and without including any royalty interest of us;

 

(b)                                 in relation to wells, thetotal number of wells in which we have an interest; and

 

(c)                                  in relation to properties, thetotal area of properties in which we have an interest.

 

2.                                       “**Net**” means:

 

(a)                                  in relation to our interest inproduction and reserves, our interest (operating and non-operating) afterdeduction of royalty obligations, plus our royalty interest in production orreserves;

 

(b)                                 in relation to wells, thenumber of wells obtained by aggregating our working interest in each of ourgross wells; and

 

(c)                                  in relation to our interest ina property, the total area in which we have an interest multiplied by theworking interest we owned.

 

3.                                       Columns may not add due torounding.

 

4.                                       The crude oil, natural gasliquids and natural gas reserves estimates presented in the GLJ Report arebased on the definitions and guidelines contained in the CSA Notice 51-324 —Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities andthe Canadian Oil and Gas Evaluation Handbook (COGE Handbook).  A summary of those definitions are set forthbelow:

 

**ReservesCategories**

** **

Reserves are estimated remaining quantitiesof oil and natural gas and related substances anticipated to be recoverablefrom known accumulations, from a given date forward, based on analysis ofdrilling, geological, geophysical and engineering data; the use of establishedtechnology; and specified economic conditions.

 

Reserves are classified according to thedegree of certainty associated with the estimates.

 

(a)                                  **Provedreserves**arethose reserves that can be estimated with a high degree of certainty to berecoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.

 

(b)                                 **Probablereserves**are those additional reserves that are less certain to be recovered than provedreserves. It is equally likely that the actual remaining quantities recoveredwill be greater or less than the sum of the estimated proved plus probablereserves.

 

Other criteria that must also be met forthe categorization of reserves are provided in the COGE Handbook.

 

Each of the reserves categories (proved andprobable) may be divided into developed and undeveloped categories:

 

(c)                                  **Developedreserves**are those reserves that are expected to be recovered from existing wells andinstalled facilities or, if facilities have not been installed, that wouldinvolve a low expenditure (for example, when compared to the cost of drilling awell) to put the reserves on production. The developed category may besubdivided into producing and non-producing.

 

11

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(i)            **Developed producing reserves** are those reserves that are expected to be recovered fromcompletion intervals open at the time of the estimate. These reserves may becurrently producing or, if shut-in, they must have previously been onproduction, and the date of resumption of production must be known withreasonable certainty.

 

(ii)           **Developed non-producing reserves** are those reserves that either have not been on production, or havepreviously been on production, but are shut-in, and the date of resumption ofproduction is unknown.

 

(d)           **Undeveloped reserves** arethose reserves expected to be recovered from known accumulations where asignificant expenditure (for example, when compared to the cost of drilling awell) is required to render them capable of production. They must fully meetthe requirements of the reserves classification (proved, probable) to whichthey are assigned.

 

Inmulti-well pools it may be appropriate to allocate total pool reserves betweenthe developed and undeveloped categories or to subdivide the developed reservesfor the pool between developed producing and developed non-producing. Thisallocation should be based on the estimator’s assessment as to the reservesthat will be recovered from specific wells, facilities and completion intervalsin the pool and their respective development and production status.

 

**Levels ofCertainty for Reported Reserves**

** **

Thequalitative certainty levels referred to in the definitions above areapplicable to individual reserves entities (which refers to the lowest level atwhich reserves calculations are performed) and to reported reserves (whichrefers to the highest level sum of individual entity estimates for whichreserves are presented). Reported reserves should target the following levelsof certainty under a specific set of economic conditions:

 

(a)           atleast a 90 per cent probability that the quantities actually recovered willequal or exceed the estimated proved reserves; and

 

(b)           atleast a 50 per cent probability that the quantities actually recovered willequal or exceed the sum of the estimated proved plus probable reserves.

 

Aqualitative measure of the certainty levels pertaining to estimates preparedfor the various reserves categories is desirable to provide a clearerunderstanding of the associated risks and uncertainties. However, the majorityof reserves estimates will be prepared using deterministic methods that do notprovide a mathematically derived quantitative measure of probability. Inprinciple, there should be no difference between estimates prepared usingprobabilistic or deterministic methods.

 

Additionalclarification of certainty levels associated with reserves estimates and theeffect of aggregation is provided in the COGE Handbook.

 

5.             Forecastprices and costs

 

Theseare prices and costs that are generally acceptable as being a reasonableoutlook of the future as of the evaluation effective date.  To the extent that there are fixed orpresently determinable future prices or costs to which we are legally bound bya contractual or other obligation to supply a physical product, including thosefor an extension period of a contract that is likely to be extended, thoseprices or costs shall be incorporated into the forecast prices.

 

Theforecast cost and price assumptions include increases in wellhead sellingprices and take into account inflation with respect to future operating andcapital costs.  Crude oil, natural gasand natural gas liquids benchmark reference pricing, as at December 31, 2009,inflation and exchange rates utilized in the GLJ Report were as follows:

 

12

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SUMMARYOF PRICING AND INFLATION RATE ASSUMPTIONS

as of December31, 2009

FORECASTPRICES AND COSTS

 
| ** ** | ** ** | **OIL**                               | ** ** | **NATURAL**                                        | ** ** | **EDMONTON LIQUIDS PRICES**                   | ** ** | ** **                                     | ** ** | ** **                             | ** ** |
|------------|------------|---------------------------------------|------------|----------------------------------------------------|------------|-----------------------------------------------|------------|------------------------------------------------|------------|----------------------------------------|------------|
| **Year**   | ** ** | **WTI  Cushing  Oklahoma  ($US/bbl)** | ** ** | **Edmonton   Par Price  40° API  ($Cdn/bbl)** | ** ** | **Hardisty  Heavy  12° API  ($Cdn/bbl)** | ** ** | **Cromer  Medium  29.3° API  ($Cdn/bbl)** | ** ** | **GAS  AECO Gas  Price  ($Cdn/MMbtu)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **INFLATION  RATES****(1)****%/Year** | ** ** | **EXCHANGE  RATE****(2)****($US/$Cdn)** | ** ** |
|       |       |                                  |       |                                               |       |                                          |       |                                           |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| Forecast   |       |                                  |       |                                               |       |                                          |       |                                           |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| 2010       |       | 80.00                                 |       | 83.26                                              |       | 64.99                                         |       | 76.60                                          |       | 5.96                                   |       | 52.46 |   | 64.11 |   | 84.93 |   | 2 | % | 0.950 |   |
| 2011       |       | 83.00                                 |       | 86.42                                              |       | 65.24                                         |       | 78.64                                          |       | 6.79                                   |       | 54.45 |   | 66.54 |   | 88.15 |   | 2 | % | 0.950 |   |
| 2012       |       | 86.00                                 |       | 89.58                                              |       | 65.33                                         |       | 80.62                                          |       | 6.89                                   |       | 56.43 |   | 68.98 |   | 91.37 |   | 2 | % | 0.950 |   |
| 2013       |       | 89.00                                 |       | 92.74                                              |       | 65.26                                         |       | 82.54                                          |       | 6.95                                   |       | 58.42 |   | 71.41 |   | 94.59 |   | 2 | % | 0.950 |   |
| 2014       |       | 92.00                                 |       | 95.90                                              |       | 67.52                                         |       | 85.35                                          |       | 7.05                                   |       | 60.42 |   | 73.84 |   | 97.82 |   | 2 | % | 0.950 |   |
| 2015       |       | 93.84                                 |       | 97.84                                              |       | 68.90                                         |       | 87.07                                          |       | 7.16                                   |       | 61.64 |   | 75.33 |   | 99.79 |   | 2 | % | 0.950 |   |
| 2016       |       | 95.72                                 |       | 99.81                                              |       | 70.32                                         |       | 88.83                                          |       | 7.42                                   |       | 62.88 |   | 76.85 |   | 101.81 |   | 2 | % | 0.950 |   |
| 2017       |       | 97.64                                 |       | 101.83                                             |       | 71.76                                         |       | 90.63                                          |       | 7.95                                   |       | 64.15 |   | 78.41 |   | 103.86 |   | 2 | % | 0.950 |   |
| 2018       |       | 99.59                                 |       | 103.88                                             |       | 73.22                                         |       | 92.46                                          |       | 8.52                                   |       | 65.45 |   | 79.99 |   | 105.96 |   | 2 | % | 0.950 |   |
| 2019       |       | 101.58                                |       | 105.98                                             |       | 74.72                                         |       | 94.32                                          |       | 8.69                                   |       | 66.77 |   | 81.60 |   | 108.10 |   | 2 | % | 0.950 |   |
| Thereafter |       | (3                                    | )          | (3                                                 | )          | (3                                            | )          | (3                                             | )          | (3                                     | )          | (3 | ) | (3 | ) | (3 | ) | 2 | % | 0.950 |   |

 

----

| Notes: |
|--------|
| (1)    |   | Inflation rates for forecasting costs. |
| (2)    |   | Exchange rates used to generate the  benchmark reference prices in this table. |
| (3)    |   | Prices  escalate 2.0 per cent per year from 2019. |

 

Weighted average actual prices realized forthe year ended December 31, 2009, were $4.18/Mcf for natural gas, $62.51/bblfor light and medium crude oil, $55.74/bbl for heavy crude oil and $40.67/bblfor natural gas liquids.  Only a minoramount of our production is characterized as heavy oil.

 

6.             FutureDevelopment Costs

 

Thefollowing table sets forth development costs deducted in the estimation of ourfuture net revenue attributable to the reserves categories noted below.

 
| **Year**                       | ** ** | **Proved Reserves  (M$)** | ** ** | **Proved Plus Probable Reserves (M$)** | ** ** |
|--------------------------------|------------|---------------------------|------------|----------------------------------------|------------|
|                           |       |                      |       |                                   |       |
| 2010                           |       | 378,193                   |       | 434,015                                |       |
| 2011                           |       | 284,629                   |       | 376,677                                |       |
| 2012                           |       | 140,518                   |       | 220,160                                |       |
| 2013                           |       | 110,333                   |       | 237,255                                |       |
| 2014                           |       | 20,337                    |       | 127,927                                |       |
| Remainder                      |       | 126,147                   |       | 215,846                                |       |
| Total:  Undiscounted           |       | 1,060,157                 |       | 1,611,880                              |       |
| Total:  Discounted at 10%/year |       | 847,109                   |       | 1,249,200                              |       |

 

Weexpect to fund the development costs of the reserves through a combination ofcash flow from operating activities, debt, and the sale of existing assets andthe issuance of Trust Units.

 

Therecan be no guarantee that funds will be available or that we will allocatefunding to develop all of the reserves attributed in the GLJ Report.  Failure to develop those reserves would havea negative impact on future cash flow from operating activities.

 

13

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Theinterest or other costs of external funding are not included in the reservesand future net revenue estimates and would reduce reserves and future netrevenue to some degree depending upon the funding sources utilized.  We do not anticipate that interest or otherfunding costs would make development of any property uneconomic.

 

7.             Estimatedfuture well abandonment costs related to reserves wells have been taken into accountby GLJ in determining the aggregate future net revenue therefrom.

 

8.             Theforecast price and cost assumptions assumed the continuance of current laws andregulations.

 

9.             Allfactual data supplied to GLJ was accepted as represented.  No field inspection was conducted.

 

10.           Theestimates of future net revenue presented in the tables above do not representfair market value.

 

**Reconciliationsof Changes in Reserves**

** **

Thefollowing table sets forth the reconciliation of our gross reserves as at December31, 2009, using forecast price and cost estimates derived from the GLJReport.  Gross reserves as at December 31,2009 and as at December 31, 2008 include working interest reserves beforeroyalties payable and without including gross royalties receivable.

 

RECONCILIATIONOFGROSS RESERVESBY PRINCIPAL PRODUCT TYPEFORECAST****PRICES AND COSTS

 
| ** **           | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL**        | ** ** | **NATURAL GAS**                    | ** ** |
|----------------------|------------|--------------------------|------------|----------------------|------------|------------------------------------|------------|
| **FACTORS**          | ** ** | **Proved  (Mbbl)**       | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Mbbl)** | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Bcf)** | ** ** | **Probable  (Bcf)** | ** ** | **Proved  Plus  Probable  (Bcf)** | ** ** |
|                 |       |                     |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December  31, 2008   |       | 104,912                  |       | 30,137               |       | 135,049                            |       | 2,366 |   | 640 |   | 3,006 |   | 736.9 |   | 263.1 |   | 1,000.0 |   |
|                 |       |                     |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Discoveries          |       | 11                       |       | 4                    |       | 15                                 |       | 0 |   | 0 |   | 0 |   | 1.3 |   | 0.4 |   | 1.7 |   |
| Extensions           |       | 449                      |       | 572                  |       | 1,021                              |       | 0 |   | 0 |   | 0 |   | 110.9 |   | 109.5 |   | 220.5 |   |
| Infill  Drilling     |       | 1,961                    |       | 432                  |       | 2,393                              |       | 12 |   | 2 |   | 14 |   | 61.4 |   | 33.3 |   | 94.6 |   |
| Improved  Recovery   |       | 1,862                    |       | 360                  |       | 2,222                              |       | 16 |   | 2 |   | 18 |   | 0.8 |   | 0.1 |   | 0.9 |   |
| Technical  Revisions |       | 2,123                    |       | (1,510               | )          | 613                                |       | 106 |   | (30 | ) | 76 |   | 31.0 |   | 3.5 |   | 34.6 |   |
| Acquisitions         |       | 1,366                    |       | 1,841                |       | 3,207                              |       | 0 |   | 0 |   | 0 |   | 37.5 |   | 26.2 |   | 63.7 |   |
| Dispositions         |       | (241                     | )          | (183                 | )          | (424                               | )          | 0 |   | 0 |   | 0 |   | (0.1 | ) | 0.0 |   | (0.1 | ) |
| Economic  Factors    |       | (69                      | )          | (46                  | )          | (115                               | )          | 36 |   | 8 |   | 44 |   | (3.2 | ) | (1.2 | ) | (4.4 | ) |
| Production           |       | (9,618                   | )          | 0                    |       | (9,618                             | )          | (324 | ) | 0 |   | (324 | ) | (69.3 | ) | 0.0 |   | (69.3 | ) |
|                 |       |                     |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December  31, 2009   |       | 102,756                  |       | 31,607               |       | 134,363                            |       | 2,212 |   | 622 |   | 2,834 |   | 907.3 |   | 434.9 |   | 1,342.3 |   |

 
| ** **           | ** ** | **NATURAL GAS LIQUIDS** | ** ** | **TOTAL**            | ** ** |
|----------------------|------------|-------------------------|------------|----------------------|------------|
| **FACTORS**          | ** ** | **Proved  (Mbbl)**      | ** ** | **Probable  (Mbbl)** | ** ** | **Proved Plus  Probable  (Mbbl)** | ** ** | **Proved  (mboe)** | ** ** | **Probable  (mboe)** | ** ** | **Proved Plus  Probable  (mboe)** | ** ** |
|                 |       |                    |       |                 |       |   |   |   |   |   |   |   |   |
| December  31, 2008   |       | 11,057                  |       | 3,329                |       | 14,386 |   | 241,154 |   | 77,959 |   | 319,114 |   |
|                 |       |                    |       |                 |       |   |   |   |   |   |   |   |   |
| Discoveries          |       | 3                       |       | 1                    |       | 4 |   | 225 |   | 77 |   | 302 |   |
| Extensions           |       | 371                     |       | 218                  |       | 588 |   | 19,310 |   | 19,045 |   | 38,355 |   |
| Infill  Drilling     |       | 456                     |       | 295                  |       | 750 |   | 12,661 |   | 6,271 |   | 18,932 |   |
| Improved  Recovery   |       | 14                      |       | 5                    |       | 19 |   | 2,024 |   | 382 |   | 2,406 |   |
| Technical  Revisions |       | 202                     |       | 5                    |       | 207 |   | 7,600 |   | (945 | ) | 6,655 |   |
| Acquisitions         |       | 606                     |       | 440                  |       | 1,046 |   | 8,225 |   | 6,646 |   | 14,871 |   |
| Dispositions         |       | (1                      | )          | 0                    |       | (1 | ) | (257 | ) | (186 | ) | (443 | ) |
| Economic  Factors    |       | (19                     | )          | (11                  | )          | (30 | ) | (583 | ) | (248 | ) | (831 | ) |
| Production           |       | (1,333                  | )          | 0                    |       | (1,333 | ) | (22,817 | ) | 0 |   | (22,817 | ) |
|                 |       |                    |       |                 |       |   |   |   |   |   |   |   |   |
| December  31, 2009   |       | 11,355                  |       | 4,281                |       | 15,637 |   | 267,543 |   | 109,000 |   | 376,543 |   |

 

14

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**AdditionalInformation Relating to Reserves Data**

 

***Proved and Probable Undeveloped Reserves***

*** ***

Undevelopedreserves are attributed by GLJ in accordance with standards and procedurescontained in the COGE Handbook.  Provedundeveloped reserves are those reserves that can be estimated with a highdegree of certainty and are expected to be recovered from known accumulationswhere a significant expenditure is required to render them capable ofproduction.  Probable undevelopedreserves are those reserves that are less certain to be recovered than provedreserves and are expected to be recovered from known accumulations where asignificant expenditure is required to render them capable of production.

 

Thefollowing table discloses by each product type the volumes of proved andprobable undeveloped reserves that were first attributed in each of the mostrecent three financial years and, in the aggregate, before that time.

 

**Proved Undeveloped Reserves**

 
| ** ** | ** ** | **Light & Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**  | ** ** | **Natural Gas  (MMcf)** | ** ** | **Natural Gas Liquids  (Mbbl)** | ** ** | **Oil Equivalent  (mboe)** | ** ** |
|------------|------------|------------------------------------|------------|------------------------|------------|-------------------------|------------|---------------------------------|------------|----------------------------|------------|
| ** ** | ** ** | **First  Attributed**              | ** ** | **Total at  Year-end** | ** ** | **First  Attributed**   | ** ** | **Total at  Year-end**          | ** ** | **First  Attributed**      | ** ** | **Total at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total at  Year-end** | ** ** |
| Prior      |       | 11,861                             |       | 11,861                 |       | —                  |       | —                          |       | 121,976                    |       | 121,976 |   | 1,827 |   | 1,827 |   | 34,017 |   | 34,017 |   |
| 2007       |       | 2,401                              |       | 11,131                 |       | 11                      |       | 11                              |       | 40,101                     |       | 122,061 |   | 235 |   | 1,484 |   | 9,331 |   | 32,970 |   |
| 2008       |       | 865                                |       | 7,919                  |       | —                  |       | —                          |       | 152,082                    |       | 268,684 |   | 683 |   | 2,000 |   | 26,895 |   | 54,700 |   |
| 2009       |       | 2,093                              |       | 8,655                  |       | —                  |       | —                          |       | 118,891                    |       | 388,364 |   | 642 |   | 2,636 |   | 22,550 |   | 76,018 |   |

 

**Probable Undeveloped Reserves**

 
| ** ** | ** ** | **Light & Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)**  | ** ** | **Natural Gas  (MMcf)** | ** ** | **Natural Gas Liquids  (Mbbl)** | ** ** | **Oil Equivalent  (mboe)** | ** ** |
|------------|------------|------------------------------------|------------|------------------------|------------|-------------------------|------------|---------------------------------|------------|----------------------------|------------|
| ** ** | ** ** | **First  Attributed**              | ** ** | **Total at  Year-end** | ** ** | **First  Attributed**   | ** ** | **Total at  Year-end**          | ** ** | **First  Attributed**      | ** ** | **Total at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total at  Year-end** | ** ** |
| Prior      |       | 10,331                             |       | 10,331                 |       | 258                     |       | 258                             |       | 56,020                     |       | 56,020 |   | 1,002 |   | 1,002 |   | 20,928 |   | 20,928 |   |
| 2007       |       | 1,832                              |       | 10,057                 |       | 113                     |       | 211                             |       | 22,534                     |       | 67,837 |   | 178 |   | 1,034 |   | 5,879 |   | 22,608 |   |
| 2008       |       | 972                                |       | 8,511                  |       | —                  |       | 93                              |       | 79,623                     |       | 153,050 |   | 283 |   | 1,346 |   | 14,526 |   | 35,458 |   |
| 2009       |       | 4,244                              |       | 10,435                 |       | —                  |       | 100                             |       | 156,403                    |       | 299,771 |   | 840 |   | 2,083 |   | 31,151 |   | 62,580 |   |

 

Over 87per cent of the proved plus probable undeveloped reserves are located in theDawson, Montney West, Ante Creek, and Weyburn area properties.  In each case, we have planned a program forthe development of a portion of the undeveloped reserves in these areas in 2010and beyond.

 

In somecases it will take us longer than two years to develop these reserves.  We plan to develop the majority of the provedundeveloped reserves in the reserves evaluation over the next four years andplan to develop the majority of the probable undeveloped reserves over the nextsix years.  The pace of development ofthese reserves is influenced by many factors, including the ongoing developmentof the infrastructure in the Montney and West Montney areas, and the outcomesof the yearly drilling and reservoir evaluations and a variety of othereconomic factors.

 

***Significant Factors or Uncertainties***

*** ***

We havea significant amount of proved undeveloped and probable reserves assigned tothe Dawson and the Montney West Area gas fields in northeast BritishColumbia.  Sophisticated and expensivetechnology is required for these wells to produce.  At the current prices, these wells areeconomic; however, should gas prices fall materially, the wells may not beeconomic to drill.

 

Degradationin future commodity price forecasts relative to the forecast in the GLJ Reportcan also have a negative impact on the economics of the development of theundeveloped reserves, unless significant moderation in the future costs ofdevelopment are not also realized.

 

15

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**Other Oil andGas Information**

** **

Our portfolio of properties as at December 31, 2009 includes bothunitized and non-unitized oil and natural gas production.  In general, the properties contain long life,low decline rate reserves and include interests in several major oil and gasfields.

 

***Principal Properties***

*** ***

The following is a description of our principal oil and natural gasproperties as at December 31, 2009. Reserves amounts are stated at December 31, 2009, based on escalatedcost and price assumptions as evaluated in the GLJ Report prepared by GLJ (see“Statement of Reserves Data and Other Oil and Gas Information”).  Information in respect of gross and net acresand well counts are as at December 31, 2009, and information in respect ofproduction is for the year ended December 31, 2009 except where indicatedotherwise.  Due to the fact that we havebeen active at acquiring additional interests in our principal properties, theworking interest share and interest in gross and net acres and wells as at December31, 2009 may not directly correspond to the stated production for the yearwhich only includes production since the date the interests were acquired byus.  The estimates of reserves and futurenet revenue for individual properties may not reflect the same confidence levelas estimates of reserves and future net revenue for all properties, due to theeffects of aggregation.

 

All of the properties described below are located in the WesternCanadian Sedimentary Basin and within the Canadian provinces of BritishColumbia, Alberta or Saskatchewan.  Theproperties represent 72 per cent of the total gross proved plus probablereserves as assigned by GLJ in the GLJ Report. There are no other properties which individually account for more than2.2 per cent of the total gross proved plus probable reserves as assigned byGLJ in the GLJ Report.  Other thanMontney West, which commenced production in January, 2010, there are no othermaterial properties to which reserves have been attributed which are capable ofproducing but which are not producing at December 31, 2009 and there are nomaterial statutory or mandatory relinquishments, surrenders, back-ins orchanges in ownership provisions.

 
| ** **                 | ** ** | **2009  Gross Reserves and Gross Production** | ** ** |
|----------------------------|------------|-----------------------------------------------|------------|
| ** **                 | ** ** | **Light  &  Medium  Crude Oil**           | ** ** | **Heavy  Oil** | ** ** | **Natural  Gas** | ** ** | **Natural  Gas  Liquids** | ** ** | **Total  Oil  equivalent********Production** | ** ** | **Proved  Reserves** | ** ** | **Proved  plus  Probable Reserves** | ** ** |
| ** **                 | ** ** | **(bbl/d)**                                   | ** ** | **(bbl/d)** | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** | **(boe/d)** | ** ** | **(mboe)** | ** ** | **(mboe)** | ** ** | **(%)** | ** ** |
|                       |       |                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Dawson                     |       | 2                                             |       | — |   | 52.1 |   | 225 |   | 8,914 |   | 67,152 |   | 101,798 |   | 27.0 |   |
| Ante Creek                 |       | 2,154                                         |       | 52 |   | 16.3 |   | 393 |   | 5,308 |   | 25,705 |   | 38,139 |   | 10.1 |   |
| Redwater                   |       | 3,783                                         |       | — |   | 1.1 |   | 178 |   | 4,141 |   | 22,067 |   | 26,896 |   | 7.1 |   |
| Lougheed                   |       | 2,341                                         |       | — |   | — |   | 96 |   | 2,437 |   | 5,552 |   | 6,924 |   | 1.8 |   |
| Jenner                     |       | —                                        |       | — |   | 13.8 |   | — |   | 2,305 |   | 9,317 |   | 11,860 |   | 3.1 |   |
| Pouce Coupe                |       | 20                                            |       | — |   | 12.6 |   | 61 |   | 2,178 |   | 2,773 |   | 3,487 |   | 0.9 |   |
| Hatton                     |       | —                                        |       | — |   | 11.9 |   | — |   | 1,986 |   | 7,327 |   | 8,746 |   | 2.3 |   |
| Weyburn Unit               |       | 1,902                                         |       | — |   | — |   | — |   | 1,902 |   | 10,381 |   | 15,500 |   | 4.1 |   |
| North Pembina Cardium Unit |       | 1,614                                         |       | — |   | 1.0 |   | 83 |   | 1,857 |   | 12,511 |   | 15,072 |   | 4.0 |   |
| Berrymoor Cardium Unit     |       | 1,422                                         |       | — |   | 1.4 |   | 112 |   | 1,764 |   | 7,957 |   | 10,174 |   | 2.7 |   |
| Montney West               |       | —                                        |       | — |   | — |   | — |   | — |   | 14,704 |   | 32,216 |   | 8.6 |   |

 

***Dawson***

 

TheDawson property is located in northeast British Columbia. We are the operatorand own an average land interest of 94 per cent in approximately 38,126 grosshectares (35,848 net hectares).  Weoperate a large area compression facility where the natural gas and liquids aresent to a third party operated facility. During 2009, gross production from thearea averaged 8,914 boe/d of natural gas and natural gas liquids from 95 netwells principally from the upper Montney zone. During 2009, 29 new wells were drilled and construction began on a 60mmcf per day gas processing facility. GLJ assigned gross proved reserves of67,152 mboe and gross proved plus probable reserves of 101,798 mboe of naturalgas and natural gas liquids to this area, or 27 per cent of total gross provedplus probable reserves.  We are in theprocess of completing a 60 MMcfpd gas plant for production from the Dawson areawhich is capable of being tied into the gas plant on completion and haveinitiated planning for the construction of an additional 60 MMcfpd gas plantfor anticipated production from the Dawson area.

 

16

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***Ante Creek***

 

The Ante Creek property is located in northwestAlberta. We are the operator and own an average land interest of 95 per cent.Oil production is processed through three operated facilities, while the gas isprocessed through one operated facility and one third party facility. During2009, gross production from the area averaged 5,308 boe/d of oil, natural gasand natural gas liquids from 180 net wells. During 2009, five new wells weredrilled. GLJ assigned gross proved reserves of 25,705 mboe and gross provedplus probable reserves of 38,139 mboe of oil, natural gas and natural gasliquids to this area, or 10.1 per cent of total gross proved plus probablereserves.

 

***Redwater***

*** ***

TheRedwater property is located in central Alberta. We are the operator and own anaverage land interest of 86 per cent. Oil and solution gas are both processedat an operated central facility. During 2009, gross production from the areaaveraged 4,141 boe/d of oil, natural gas and natural gas liquids from 380 netwells. During 2009, three new wells were drilled. GLJ assigned gross provedreserves of 22,067 mboe and gross proved plus probable reserves of 26,896 mboeof oil, natural gas and natural gas liquids to this area, or 7.1 per cent oftotal gross proved plus probable reserves.

 

ARCbelieves that the Redwater field is a prime candidate for Enhanced Oil Recovery(“EOR”) through the use of Carbon Dioxide (“CO2”)injection.  Redwater is one of thelargest conventional oil pools in Canada and has been producing for over 50 years.  While significant oil production from ourproperty has occurred to date, we believe that there are substantial quantitiesof oil remaining in the reservoir which are unrecoverable with conventionaltechnology.

 

During2009, ARC commenced production operations at the pilot EOR project in Redwater,while continuing the injection of CO2.  The pilot is designed to confirm whether theRedwater reef is amenable to CO2 flooding and thatincremental oil can be mobilized and recovered. Results are not expected before the end of 2010.  Additionally, prior to commercial operations,large amounts of CO2 need to be acquired oneconomic terms for the Redwater EOR project to proceed.  Currently, there are no large scale CO2 capture facilities orinfrastructure to transport CO2 in Alberta. Large infrastructure investments are required to capture, transport andinject CO2 and long term agreements willneed to be negotiated with emitters for the CO2 supply. For these types of projects to be possible, higher commodity prices willneed to prevail and most importantly, governments will need to clearlyestablish long term regulations surrounding the capture of CO2 emissions.   There is no assurance that the Redwater EORproject will proceed to a commercial phase or become economically viable.

 

***Lougheed***

*** ***

TheLougheed property is located in southeast Saskatchewan. We are the operator andown an average land interest of 80 per cent. Production is handled by anoperated battery and gas plant. During 2009, gross production from the areaaveraged 2,437 boe/d of oil and natural gas liquids from 125 net wells. During2009, no new wells were drilled. GLJ assigned gross proved reserves of 5,552mboe and gross proved plus probable reserves of 6,924 mboe of oil and naturalgas liquids to this area, or 1.8 per cent of total gross proved plus probablereserves.

 

***Jenner***

*** ***

TheJenner property is located in southeast Alberta. We own a combination ofoperated and non-operated acreage with an average land interest of 88 per cent.We operate four gas compression and dehydration facilities in the area. During2009, gross production from the area averaged 2,305 boe/d of natural gas from835 net wells. During 2009, no new wells were drilled. GLJ assigned grossproved reserves of 9,317 mboe and gross proved plus probable reserves of 11,860mboe of natural gas to this area, or 3.1 per cent of total gross proved plusprobable reserves.

 

***Pouce Coupe***

*** ***

ThePouce Coupe property is located in northwest Alberta. We are the operator andown an average land interest of 75 per cent. The sweet gas is processed throughan operated gas plant and the sour gas flows to a third party processing plant.During 2009, gross production from the area averaged 2,178 boe/d of oil,natural gas and natural gas liquids from 39 net wells. During 2009, one wellwas drilled. GLJ assigned gross proved reserves of 2,773 mboe 

 

17

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andgross proved plus probable reserves of 3,487 mboe of oil, natural gas andnatural gas liquids to this area, or 0.9 per cent of total gross proved plusprobable reserves.

 

***Hatton***

*** ***

TheHatton property is located in southwest Saskatchewan. We own a combination ofoperated and non-operated acreage with an average land interest of 44 per cent.The operated production flows through three operated compression anddehydration facilities where our working interest ranges from 50 to 100 percent. During 2009, gross production from the area averaged 1,986 boe/d ofnatural gas from 468 net wells. During 2009, 23 new wells were drilled. GLJassigned gross proved reserves of 7,327 mboe and gross proved plus probablereserves of 8,746 mboe of natural gas to this area, or 2.3 per cent of totalgross proved plus probable reserves.

 

***Weyburn Unit***

*** ***

TheWeyburn Unit is located in southeast Saskatchewan. EnCana Corporation operatesthe unit and we have a working interest of 6.95 per cent. The unit is currentlyundergoing a CO2 flood for enhanced oil recovery. During 2009gross production from the unit averaged 1,902 boe/d of oil from 58 net wells.During 2009, six new wells were drilled. GLJ assigned gross proved reserves of10,381 mboe and gross proved plus probable reserves of 15,500 mboe of oil andnatural gas liquids to this unit, or 4.1 per cent of total gross proved plus probablereserves.

 

***North Pembina Cardium Unit***

*** ***

TheNorth Pembina Cardium Unit No. 1 is located in central Alberta. We are theoperator and own a 45.57 per cent interest in the unit. Production is processedthrough two operated oil treatment facilities and one operated solution gasplant. During 2009, gross production from the unit averaged 1,857 boe/d of oil,natural gas and natural gas liquids from 179 net wells. During 2009, four newwells were drilled. GLJ assigned gross proved reserves of 12,511 mboe and grossproved plus probable reserves of 15,072 mboe of oil, natural gas and naturalgas liquids to this unit, or four per cent of total gross proved plus probablereserves.

 

***Berrymoor Cardium Unit***

*** ***

TheBerrymoor Cardium Unit is located in central Alberta. We are the operator andown a 73.25 per cent interest in the unit. Oil is processed at an operatedbattery while the solution gas flows to a third party facility.  During 2009, gross production from the unitaveraged 1,764 boe/d of oil, natural gas and natural gas liquids from 91 netwells. During 2009, one new well was drilled. GLJ assigned gross provedreserves of 7,957 mboe and gross proved plus probable reserves of 10,174 mboeof oil, natural gas and natural gas liquids to this unit, or 2.7 per cent of totalgross proved plus probable reserves.

 

***Montney West***

 

TheMontney West property is located in northeast British Columbia.  We own an average land interest of 79 percent in approximately 24,425 gross hectares (19,254 net hectares) in theMontney West Area which we believe is prospective in the upper Montney andother horizons.  The Montney West Areahas been assigned gross proved reserves of 14,704 boe and gross proved plusprobable reserves of 32,216 mboe in the GLJ Report which are capable ofproducing but which are not yet producing material volumes due to pipeline,processing and other infrastructure constraints.  In 2009, we had royalty income in the arearesulting from interests we hold in third party wells, equivalent to 7 boe/d ofnatural gas and natural gas liquids.  Wecurrently plan to construct a 60 MMcfpd gas plant for production from theMontney West Area in 2012.

 

***Oil And Gas Wells***

*** ***

Thefollowing table sets forth the number and status of wells in which we had aworking interest as at December 31, 2009.

 

18

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| ** **        | ** ** | **Oil Wells** | ** ** | **Natural Gas Wells** | ** ** |
|-------------------|------------|---------------|------------|-----------------------|------------|
| ** **        | ** ** | **Producing** | ** ** | **Non-Producing**     | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** |
| ** **        | ** ** | **Gross**     | ** ** | **Net**               | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|              |       |          |       |                  |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Alberta           |       | 3,809         |       | 1,596                 |       | 1,162 |   | 163 |   | 4,517 |   | 1,965 |   | 253 |   | 53 |   |
| British  Columbia |       | 7             |       | 1                     |       | 1 |   | — |   | 307 |   | 101 |   | 55 |   | 31 |   |
| Saskatchewan      |       | 2,173         |       | 812                   |       | 319 |   | 91 |   | 5,577 |   | 902 |   | 60 |   | 20 |   |
| Manitoba          |       | 589           |       | 137                   |       | 20 |   | 3 |   | — |   | — |   | — |   | — |   |
| Total             |       | 6,578         |       | 2,547                 |       | 1,502 |   | 257 |   | 10,401 |   | 2,968 |   | 368 |   | 103 |   |

 

***Properties with no Attributable Reserves***

 

Thefollowing table sets out our undeveloped land holdings as at December 31, 2009.

 
| ** **        | ** ** | **Undeveloped Hectares** | ** ** |
|-------------------|------------|--------------------------|------------|
| ** **        | ** ** | **Gross**                | ** ** | **Net** | ** ** |
|              |       |                     |       |   |   |
| Alberta           |       | 245,000                  |       | 134,500 |   |
| British  Columbia |       | 82,100                   |       | 61,300 |   |
| Manitoba          |       | 3,900                    |       | 3,700 |   |
| Saskatchewan      |       | 91,600                   |       | 60,500 |   |
| Total             |       | 422,600                  |       | 260,000 |   |

 

InBritish Columbia, we have 55**,**800 gross hectares and 50,700 net hectares in Dawson and theMontney West Area which have varying degrees of prospectively in the Montneyzones.  For more information, see“Statement of Reserves Data and Other Oil and Gas Information - AdditionalInformation Relating to Reserve Data — Principal Properties — Dawson andMontney West “.

 

Wecurrently have no material work commitments on these lands.  There are no material expiries in our coreholdings.

 

***Forward Contracts***

*** ***

We are exposed to market risks resulting from fluctuations in commodityprices, foreign exchange rates and interest rates in the normal course ofoperations.  A variety of derivativeinstruments are used to reduce our exposure to fluctuations in commodityprices, foreign exchange rates and interest rates.  We may also potentially be exposed to lossesin the event of default by the counterparties to these derivative instruments.  We manage this risk by diversifying ourderivative portfolio among a number of financially sound counterparties and bymonitoring their ongoing credit risks.

 

In general, under authorities approved by theBoard of Directors, management of ARC Resources is permitted to hedge up to amaximum of 50 per cent of forecasted production on a boe basis for up to sixmonths, 40 per cent between seven and 12 months, and 25 per cent between 13 and18 months.  In addition to theseauthorizations to management, the Board of Directors may approve longer termhedging transactions to mitigate risks relating to, and protect the economicsof, major capital expenditures.

 

We have a Risk Committee of the Board ofDirectors that reviews policies, procedures and provides oversight tomanagement in the areas of financial and business risks including activitiesrelated to our hedging program.  Ourmanagement executes financial hedging transactions to reduce the Trust’sexposure to market price fluctuations either by price protection, throughderivatives or swaps, or diversifying its price exposure in accordance with theBoard of Directors guidelines or approval on specific transactions.

 

A summary of financial and physical contracts in respect of hedgingactivities can be found in Note 13 “Financial Instruments and Risk Management”to our audited consolidated financial statements for the year ended December 31,2009 and in the section under the heading “Risk Management and HedgingActivities” in our Management Discussion and Analysis for the year ended December31, 2009 which have been filed on SEDAR at www.sedar.com, and both of whichnote and section are incorporated in this Annual Information Form by reference.

 

19

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***Additional Information Concerning Abandonment and Reclamation Costs***

*** ***

Thefollowing table sets forth information respecting future abandonment andreclamation costs for surface leases, wells, facilities and pipelines which weexpect to incur for the periods indicated.

 
| ** **                      | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Undiscounted** | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Discounted at 10%** | ** ** |
|---------------------------------|------------|------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------|------------|
| ** **                      | ** ** | **($MM)**                                                              | ** ** | **($MM)**                                                                   | ** ** |
| Total  as at December 31, 2009  |       | 1,358.7                                                                |       | 74.9                                                                        |       |
| Anticipated  to be paid in 2010 |       | 5.6                                                                    |       | 5.1                                                                         |       |
| Anticipated  to be paid in 2011 |       | 5.4                                                                    |       | 4.5                                                                         |       |
| Anticipated  to be paid in 2012 |       | 5.5                                                                    |       | 4.1                                                                         |       |

 

We willbe liable for our share of ongoing environmental obligations and for theultimate reclamation of the properties held by us upon abandonment.  We estimate that we have an interest in 6,888net wells that will require abandonment and reclamation over the next 51 yearswith the majority of payments being made in years 2050 to 2060.  These ongoing environmental obligations areexpected to be funded out of cash flow from operating activities and anybalance available in our reclamation fund.

 

We havea reclamation fund to pay future asset retirement obligation costs.  We currently estimate that the futureenvironmental and reclamation obligations in respect of our properties will beapproximately $1,359 million calculated by escalating costs at two per cent peryear (reflected in our audited consolidated financial statements as an assetretirement obligation of $149.9 million calculated by escalating costs at twoper cent per year and discounting at a blended rate of 6.5 per cent).  For more information, see Note 11 of ouraudited consolidated financial statements and the section in our Management’sDiscussion and Analysis of such financial statements under the heading “AssetRetirement Obligation and Reclamation Fund”, which note and section areincorporated in this Annual Information Form by reference and are found onSEDAR at www.sedar.com.  The Board ofDirectors of ARC Resources has approved voluntary contributions to ourreclamation fund over a twenty year period that results in minimum annualcontributions of $6 million ($6million in 2009) based on properties owned as at December 31, 2009.  During 2009, $5.9 million ($9.7 million for2008) of actual expenditures were charged against the reclamation fundresulting in a net reduction of our reclamation fund for the year of $1.4million ($3.2 million net reduction in 2008). The balance of this fund as of December 31, 2009 is $12.6 million.

 

Inaddition we have committed to a restricted reclamation trust associated withthe acquisition of the Redwater property pursuant to which ARC Resources hasagreed with the vendor of the Redwater property to contribute to such trustcertain minimum amounts, totalling approximately $110 million over a 50 yearperiod, to fund future environmental and reclamation obligations in respect ofthe Redwater properties, or to expend certain minimum amounts towardsdischarging these obligations. The restricted contribution commenced in 2006for $6.1 million and continues at a declining rate through 2055. The currentbalance of this trust as of December 31, 2009 is $20.6 million.

 

Weestimate the costs to abandon and reclaim all our shut in and producing wells,pipelines and facilities.  No estimate ofsalvage value is netted against the estimated cost.  Our model for estimating the amount andtiming of future abandonment and reclamation expenditures was created on anoperating area level.  Estimatedexpenditures for each operating area are based on the Energy ResourcesConservation Board methodology which details the cost of abandonment andreclamation in eight specific geographic regions.  Each region was assigned an average cost perwell to abandon and reclaim the wells in that area.

 

Abandonmentand reclamation costs have been estimated over a 50 year period.  Facility abandonment and reclamation costsare scheduled to be incurred in the year following the end of the reserves lifeof its associated reserve.

 

Ourestimated liability associated with well, pipelines and facilities reclamationcosts which were not deducted by GLJ in estimating future net revenue in theGLJ Report are $1,071.7 million (escalating costs at two per cent andundiscounted) and $26.9 million (escalating costs at two per cent anddiscounted at 10 per cent).  Only theabandonment costs associated with wells with reserves were deducted by GLJ inestimating future net revenue.

 

20

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***Tax Horizon***

*** ***

As aresult of our tax efficient structure, annual taxable income is currentlytransferred from ARC Resources to the Trust and from the Trust toUnitholders.  This is primarilyaccomplished through the deduction by ARC Resources of the Royalties onunderlying oil and gas properties and the deduction of interest on the LongTerm Notes.

 

Theeffect of the SIFT Rules is reflected in the after tax net revenue amountsdisclosed in the Reserves Data (Forecast Prices and Costs) in this AnnualInformation Form.  See “ARC Energy Trust— Federal Tax Changes for Income Trusts and Corporations”.

 

Untilthe SIFT tax becomes applicable to the Trust, it is expected that minimalincome taxes will be incurred by the Trust or its operating entities ascurrently structured.  However, annualoperating income retained to pay a portion of capital expenditures or used torepay debt may result in income tax liabilities within ARC Resources from timeto time.  In addition, any furtherdeclines in oil and natural gas prices and consequential reduced revenues mayresult in reduced distributions to Unitholders and income tax incurred by usResources.  See “Risk Factors — RisksRelating to Our Business and Operations”.

 

Managementand the Board of Directors continue to work on the plan for converting ourTrust to a corporation on January 1, 2011. After the conversion, the corporation would expect to allocate its cashflow among funding a portion of capital expenditures, periodic debt repayments,site reclamation expenditures, and cash payments to shareholders in the form ofdividends.  Current taxes payable by usafter converting to a corporation will be subject to normal corporate taxrates. Taxable income as a corporation will vary depending on total income andexpenses and vary with changes to commodity prices, costs, claims for bothaccumulated tax pools and tax pools associated with current yearexpenditures.  As we have $2.2 billion ofincome tax pools, it is expected that taxable income will be reduced orpotentially eliminated for the initial approximate two year period postconversion.

 

***Capital Expenditures***

*** ***

Thefollowing table summarizes capital expenditures (net of incentives and net ofcertain proceeds and including capitalized general and administrative expenses)related to our activities for the year ended December 31, 2009:

 
| ** **                      | ** ** | **2009  $MM** | ** ** |
|---------------------------------|------------|---------------|------------|
| Property  acquisition costs(1)  |       |          |       |
| Proved  properties              |       | (29.1         | )          |
| Undeveloped  properties         |       | 8.6           |       |
| Corporate  acquisition costs(2) |       | 178.9         |       |
| Exploration  costs(3)           |       | 17.4          |       |
| Development  costs(4)           |       | 326.4         |       |
| Corporate  capital costs        |       | 15.8          |       |
| Total                           |       | 518.0         |       |

 

----

| Notes: |
|--------|
| (1)    |   | Represents acquisition costs net of dispositions  and property swaps. |
| (2)    |   | For further details on Corporate  acquisition costs for 2009, see “Our Business — General Development of the  Business”. |
| (3)    |   | Includes costs of land acquired ($2.6  million), geological and geophysical capital expenditures and drilling costs  for 2009 exploration wells drilled. |
| (4)    |   | Includes costs of land acquired ($4.4  million), development and facilities capital expenditures and drilling costs  for 2009 development wells drilled. |

 

***Exploration and Development Activities***

*** ***

Thefollowing table sets forth the gross and net exploratory and development wellsthat we participated in during the year ended December 31, 2009:

 

21

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| ** **            | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** | **Total** | ** ** |
|-----------------------|------------|-----------------------|------------|-----------------------|------------|-----------|------------|
| ** **            | ** ** | **Gross**             | ** ** | **Net**               | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Light  and Medium Oil |       | 2                     |       | 2                     |       | 62        |       | 38 |   | 64 |   | 39 |   |
| Heavy  Oil            |       | —                |       | —                |       | 10        |       | — |   | 10 |   | — |   |
| Natural  Gas          |       | 2                     |       | 2                     |       | 167       |       | 97 |   | 169 |   | 99 |   |
| Service               |       | —                |       | —                |       | 8         |       | 1 |   | 8 |   | 1 |   |
| Dry                   |       | 2                     |       | 1                     |       | 2         |       | 2 |   | 4 |   | 2 |   |
| Total:                |       | 7                     |       | 4                     |       | 248       |       | 137 |   | 255 |   | 141 |   |

 

For 2010, the Trust has planned an extensive capital program of $610million.  The program comprises costs todevelop the core assets of the Trust, including the Dawson, Montney West, AnteCreek and Weyburn areas, as well as expansion of the facilities in the Dawsonand Montney West Areas.  Our capitalprogram is subject to variation throughout the year depending upon prices foroil and natural gas and there is no assurance that all or any part of ourcapital program will be expended as planned. In addition, capital expenditures may be made on the acquisition ofundeveloped land or oil and natural gas reserves.  See “Risk Factors — Risks Relating to ourBusiness and Operations”.

 

***Production Estimates***

*** ***

Thefollowing table sets out the volume of our production estimated for the yearended December 31, 2010 which is reflected in the estimate of gross provedreserves and gross probable reserves disclosed in the tables contained under“Statement of Reserves Data and Other Oil and Gas Information - Disclosure ofReserves Data”.

 
| ** **                  | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Total**   | ** ** |
|-----------------------------|------------|---------------------------|------------|---------------|------------|-----------------|------------|--------------------------|------------|-------------|------------|
| ** **                  | ** ** | **(bbl/d)**               | ** ** | **(bbl/d)**   | ** ** | **(Mcfpd)**     | ** ** | **(bbl/d)**              | ** ** | **(boe/d)** | ** ** |
| ** **                  | ** ** | **Gross**                 | ** ** | **Net**       | ** ** | **Gross**       | ** ** | **Net**                  | ** ** | **Gross**   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Total  Proved               |       | 25,298                    |       | 21,519        |       | 846             |       | 845                      |       | 236,148     |       | 202,028 |   | 3,809 |   | 2,768 |   | 69,310 |   | 58,803 |   |
| Total  Proved Plus Probable |       | 26,598                    |       | 22,575        |       | 878             |       | 874                      |       | 245,185     |       | 208,696 |   | 3,968 |   | 2,887 |   | 72,308 |   | 61,119 |   |

 

***Production History***

*** ***

The following tables summarize certain information inrespect of our production, product prices received, royalties paid, operatingexpenses and resulting netback for the periods indicated below:

 
| ** **                              | ** ** | **Quarter Ended** | ** ** | ** **     | ** ** |
|-----------------------------------------|------------|-------------------|------------|----------------|------------|
| ** **                              | ** ** | **2009**          | ** ** | **Year Ended** | ** ** |
| **(6:1)**                               | ** ** | **Mar. 31**       | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2009** | ** ** |
| Average  Daily Production(1)            |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil (bbl/d)     |       | 27,720            |       | 25,901         |       | 25,930 |   | 26,299 |   | 26,423 |   |
| Heavy  Oil (bbl/d)                      |       | 1,086             |       | 1,016          |       | 991 |   | 1,116 |   | 1,086 |   |
| Gas  (MMcfpd)                           |       | 193.8             |       | 200.2          |       | 193.1 |   | 189.0 |   | 194.0 |   |
| NGLs  (bbl/d)                           |       | 3,764             |       | 3,679          |       | 3,717 |   | 3,597 |   | 3,689 |   |
| Combined  (boe/d)                       |       | 64,872            |       | 63,969         |       | 62,824 |   | 62,520 |   | 63,538 |   |
|                                    |       |              |       |           |       |   |   |   |   |   |   |
| Average  Net Production Prices Received |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil ($/bbl)     |       | 46.76             |       | 62.92          |       | 58.99 |   | 72.95 |   | 62.51 |   |
| Heavy  Oil ($/bbl)                      |       | 38.11             |       | 57.96          |       | 52.59 |   | 64.52 |   | 55.74 |   |
| Gas  ($/Mcf)                            |       | 5.20              |       | 3.73           |       | 4.05 |   | 4.58 |   | 4.18 |   |
| NGLs  ($/bbl)                           |       | 38.86             |       | 38.89          |       | 38.89 |   | 46.12 |   | 40.67 |   |
| Combined  ($/boe)                       |       | 38.57             |       | 40.41          |       | 40.11 |   | 48.42 |   | 42.17 |   |

 

22

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| ** **                                               | ** ** | **Quarter Ended** | ** ** | ** **     | ** ** |
|----------------------------------------------------------|------------|-------------------|------------|----------------|------------|
| ** **                                               | ** ** | **2009**          | ** ** | **Year Ended** | ** ** |
| **(6:1)**                                                | ** ** | **Mar. 31**       | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2009** | ** ** |
| Royalties  Paid                                          |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil ($/bbl)                      |       | 6.95              |       | 8.65           |       | 8.73 |   | 12.28 |   | 9.63 |   |
| Heavy  Oil ($/bbl)                                       |       | 2.73              |       | 3.59           |       | 4.73 |   | 7.61 |   | 5.34 |   |
| Gas  ($/Mcf)                                             |       | 0.85              |       | 0.17           |       | 0.47 |   | 0.58 |   | 0.50 |   |
| NGLs  ($/bbl)                                            |       | 13.47             |       | 10.86          |       | 12.33 |   | 15.15 |   | 13.03 |   |
| Combined  ($/boe)                                        |       | 6.34              |       | 4.72           |       | 5.86 |   | 7.94 |   | 6.37 |   |
|                                                     |       |              |       |           |       |   |   |   |   |   |   |
| Operating  Expenses (2)(3)                               |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil ($/bbl)                      |       | 12.74             |       | 13.20          |       | 13.11 |   | 12.19 |   | 12.88 |   |
| Heavy  Oil ($/bbl)                                       |       | 16.03             |       | 12.65          |       | 12.52 |   | 12.34 |   | 12.46 |   |
| Gas  ($/Mcf)                                             |       | 1.30              |       | 1.52           |       | 1.34 |   | 1.30 |   | 1.33 |   |
| NGLs  ($/bbl)                                            |       | 8.01              |       | 7.75           |       | 8.45 |   | 6.40 |   | 7.85 |   |
| Combined  ($/boe)                                        |       | 10.12             |       | 11.02          |       | 10.28 |   | 9.91 |   | 10.19 |   |
|                                                     |       |              |       |           |       |   |   |   |   |   |   |
| Transportation  Paid                                     |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil ($/bbl)                      |       | 0.18              |       | 0.14           |       | 0.15 |   | 0.27 |   | 0.18 |   |
| Heavy  Oil ($/bbl)                                       |       | 1.50              |       | 1.29           |       | 1.12 |   | 1.09 |   | 1.15 |   |
| Gas  ($/Mcf)                                             |       | 0.28              |       | 0.25           |       | 0.26 |   | 0.27 |   | 0.26 |   |
| NGLs  ($/bbl)                                            |       | —            |       | —         |       | — |   | — |   | — |   |
| Combined  ($/boe)                                        |       | 0.95              |       | 0.85           |       | 0.88 |   | 0.92 |   | 0.89 |   |
|                                                     |       |              |       |           |       |   |   |   |   |   |   |
| Loss/(Gain)  on Commodity and Foreign Exchange Contracts |       |              |       |           |       |   |   |   |   |   |   |
| Light  and Medium Crude Oil ($/bbl)                      |       | 0.76              |       | 2.11           |       | 1.56 |   | 1.91 |   | 1.65 |   |
| Heavy  Oil ($/bbl)                                       |       | —            |       | —         |       | — |   | — |   | — |   |
| Gas  ($/Mcf)                                             |       | (0.77             | )          | (0.15          | )          | (0.50 | ) | (0.11 | ) | (0.40 | ) |
| NGLs  ($/bbl)                                            |       | —            |       | —         |       | — |   | — |   | — |   |
| Combined  ($/boe)                                        |       | (1.97             | )          | 0.46           |       | (0.88 | ) | 0.47 |   | (0.54 | ) |
|                                                     |       |              |       |           |       |   |   |   |   |   |   |
| Netback Received(4)                                      |       |              |       |           |       |   |   |   |   |   |   |
| Light and Medium Crude Oil  ($/bbl)                      |       | 26.13             |       | 38.82          |       | 35.44 |   | 46.30 |   | 38.17 |   |
| Heavy Oil ($/bbl)                                        |       | 17.85             |       | 40.43          |       | 34.22 |   | 43.48 |   | 36.79 |   |
| Gas ($/Mcf)                                              |       | 3.54              |       | 1.94           |       | 2.48 |   | 2.54 |   | 2.49 |   |
| NGLs ($/bbl)                                             |       | 17.38             |       | 20.28          |       | 18.11 |   | 24.57 |   | 19.79 |   |
| Combined ($/boe)                                         |       | 23.13             |       | 23.36          |       | 23.97 |   | 29.18 |   | 25.26 |   |

 

----

| Notes: |
|--------|
| (1)    |   | Before deduction of royalties. |
| (2)    |   | Operating expenses are composed of direct  costs incurred to operate both oil and gas wells. A number of assumptions  have been made in allocating these costs between oil, natural gas and natural  gas liquids production. |
| (3)    |   | Operating recoveries associated with  operated properties were excluded from operating costs and accounted for as a  reduction to general and administrative costs. |
| (4)    |   | Netbacks  are calculated by subtracting royalties, operating costs, transportation  costs, and losses/(gains) on commodity and foreign exchange contracts from  revenues. |

 

Each ofthe Dawson, Ante Creek and Redwater areas account for approximately 14 percent, 8 per cent and 7 per cent of the production disclosed above.  For more information, see “Statement of ReservesData and Other Oil and Gas Information - Other Oil and Gas Information —Principal Properties”.

 

**MarketingArrangements**

** **

***Natural Gas***

*** ***

During2009, we continued our marketing strategy of maintaining a high level of directcontrol and diversification of marketing and transportation arrangements forour natural gas production.

 

Theaverage natural gas price we received during 2009 was $4.18 per Mcf as comparedto $8.58 per Mcf for 2008.  This pricewas achieved with a portfolio mix that on average through the year receivedAECO index based pricing 

 

23

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for 82per cent, aggregator netback prices for 11 per cent, and Chicago Index Pricingfor 7 per cent of total production.

 

Tomanage natural gas price volatility and to stabilize the revenue stream, ournatural gas portfolio is directed towards maintaining balanced exposure to U.S.and Canadian markets with market sensitive and hedgeable pricing terms, as wellas aggregator netback arrangements.  Wealso strive for a high utilization of contracted pipeline and processingcapacity.

 

***Crude Oil and Natural Gas Liquids***

*** ***

Ourliquids production in 2009 was comprised of approximately 51 per cent lightquality crude oil (greater than 35°API), 33 per cent medium quality crude oil(25 to 35 API), four per cent heavy quality crude (less than 25°API), four percent condensate and eight per cent natural gas liquids.  During 2009, our average sales prices were$62.49 per bbl for light and medium crude oil, $55.64 per bbl for heavy crudeoil and $40.67 per bbl for natural gas liquids; these prices compare to 2008prices of $94.97 per bbl for light and medium crude oil, $77.85 per bbl forheavy crude oil and $69.71 per bbl for natural gas liquids.  Our crude oil is sold under contracts ofvarying terms of up to one year, based on market sensitive pricing terms.  Natural gas liquids are sold under annualarrangements.  Industry pricingbenchmarks for crude oil and natural gas liquids are continuously monitored toensure optimal netbacks.

 

**SHARE CAPITAL OF ARCRESOURCES**

** **

**Common Shares**

** **

ARCResources has authorized for issuance an unlimited number of common shares ofwhich 1,000,131 common shares are issued and outstanding and held by theTrust.  The voting of such shares isdelegated to ARC Resources under the Trust Indenture.  The holders of common shares are entitled tonotice of, to attend and to one vote per share held at any meeting of theshareholders of ARC Resources; to receive dividends as and when declared by theBoard of Directors of ARC Resources on the common shares as a class, andsubject to prior satisfaction of all preferential rights to dividends attachedto all shares of other classes; and in the event of any liquidation,dissolution or winding-up of ARC Resources, whether voluntary or involuntary,or any other distribution of the assets of ARC Resources among its shareholdersfor the purpose of winding-up its affairs, and subject to prior satisfaction ofall preferential rights to return of capital on dissolution attached to allshares of other classes of shares of ARC Resources ranking in priority to thecommon shares in respect of return of capital on dissolution, to sharerateably, together with the shares of any other class of shares of ARCResources ranking equally with the common shares in respect of return ofcapital on dissolution, in such assets of ARC Resources as are available fordistribution.

 

**ExchangeableShares**

** **

ARCResources is authorized to issue an unlimited number of Exchangeable Shares ofwhich there were 870,841 outstanding as at December 31, 2009.  The Exchangeable Shares rank prior to thecommon shares of ARC Resources, the second preferred shares of ARC Resourcesand any other shares ranking junior to the Exchangeable Shares with respect tothe payment of dividends and the distribution of assets in the event of theliquidation, dissolution or winding-up of ARC Resources; provided thatnotwithstanding such ranking ARC Resources shall not be restricted in any wayfrom repaying indebtedness of ARC Resources to the Trust from time totime.  The Exchangeable Share provisionshave been filed on SEDAR at www.sedar.com.

 

TheExchangeable Shares provide holders with a security having economic, ownershipand voting rights which are substantially equivalent to those of TrustUnits.  As at December 31, 2009 theExchange Ratio was 2.71953 Trust Units per Exchangeable Share.  Holders of Exchangeable Shares will notreceive distributions, rather the Exchangeable Shares are maintainedeconomically equivalent to the Trust Units by the progressive increase in theExchange Ratio to reflect distributions paid by the Trust to Unitholders.  The Exchangeable Shares are providedequivalent voting rights as those of Unitholders through an agreement (theExchangeable Share Voting and Exchange Trust Agreement) pursuant to which theholders of Exchangeable Shares can direct the Trustee to vote at meetings ofUnitholders.  The holders of ExchangeableShares are further assured of the delivery of Trust Units by us in satisfactionof the obligations of ARC Resources under the Exchangeable Share terms throughthe provisions of another agreement (the Exchangeable Share SupportAgreement).  Copies of the ExchangeableShare Voting and 

 

24

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ExchangeTrust Agreement and the Exchangeable Share Support Agreement have been filed onSEDAR at www.sedar.com.

 

ComputershareTrust Company of Canada acts as the transfer agent for the Exchangeable Shares.

 

Holdersof Exchangeable Shares are entitled to receive, as and when declared by theBoard of Directors in its sole discretion, from time to time, cumulativepreferential cash dividends in an amount per share equal to the Exchange Ratioon the preceding business day multiplied by the fair market value of a TrustUnit as at the preceding business day (determined on the basis of the weightedaverage price of the Trust Unit on the TSX for the 10 trading days precedingthat date).  It is not anticipated thatdividends will be declared or paid on the Exchangeable Shares, however theBoard of Directors has the right in its sole discretion to do so, and if so,the Exchange Ratio would be reduced accordingly to reflect such dividends.

 

ARCResources will not, without obtaining the approval of the holders of theExchangeable Shares:

 

(a)                                  pay any dividend on the common shares of ARC Resources, secondpreferred shares of ARC Resources or any other shares ranking junior to theExchangeable Shares, other than the stock dividends payable in common shares ofARC Resources or any such other shares ranking junior to the ExchangeableShares;

 

(b)                                 redeem, purchase or make any capital distribution in respect of thecommon shares of ARC Resources, second preferred shares of ARC Resources or anyother shares ranking junior to the Exchangeable Shares;

 

(c)                                  redeem or purchase any other shares of ARC Resources ranking equallywith respect to the payment of dividends or on any liquidation distribution; or

 

(d)                                 issue any shares, other than Exchangeable Shares, second preferredshares of ARC Resources or common shares of ARC Resources, which rank superiorto the Exchangeable Shares with respect to the payment of dividends or on anyliquidation distribution.

 

Notwithstandingthe foregoing, the restrictions in paragraphs (a), (b) and (c) above shall onlybe applicable if dividends which have been declared on the outstandingExchangeable Shares have not been paid in full.

 

TheExchangeable Share Provisions entitle the holder to exchange each ExchangeableShare at any time into the number of Trust Units equal to the Exchange Ratiothen in effect.  The Exchange Ratio isdetermined by reference to the distributions paid on Trust Units in a givenmonth and the current market price of the Trust Units.

 

**SecondPreferred Shares**

** **

ARCResources also has authorized an unlimited number of Second Preferred Shareswhich may at any time or from time to time be issued in one or moreseries.  Before any shares of aparticular series are issued, the Board of Directors of ARC Resources shall, byresolution, fix the number of shares that will form such series and shall,subject to the limitations set out herein, by resolution fix the designation,rights, privileges, restrictions and conditions to be attached to the SecondPreferred Shares of such series.  TheSecond Preferred Shares of each series shall rank behind the ExchangeableShares and on parity with the Second Preferred Shares of every other serieswith respect to accumulated dividends and return of capital.  The Second Preferred Shares are entitled to apreference over the Common Shares and over any other shares of ARC Resourcesranking junior to the Second Preferred Shares with respect to priority in thepayment of dividends and in the distribution of assets in the event of theliquidation, dissolution or winding-up of ARC Resources, whether voluntary orinvoluntary, or any other distribution of the assets of ARC Resources among itsshareholders forthe purpose of winding-up its affairs. As at the date hereof, there are no Second Preferred Shares, Series 1and Second Preferred Shares, Series 2 issued and outstanding.

 

25

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** **

**OTHER INFORMATIONRELATING TO OUR BUSINESS**

** **

**Borrowing**

** **

Weborrow funds from time to time to finance the purchase of properties, for capitalexpenditures or for other financial obligations or expenditures in respect ofproperties held by us or for working capital purposes.  We have a policy relating to borrowing whichrequires a quarterly assessment by management, subject to review by the Boardof Directors of ARC Resources, of the appropriateness of borrowing levels.  We have granted security in priority to theRoyalties to secure the loan of such funds.

 

Ourcredit facilities are comprised of both a bank credit facility and long-termnotes issued to major financial institutions. We may choose to repay a portion of our debt from one source and borrowfrom other parties in order to reduce borrowing costs and provide morefinancial flexibility.

 

Debtservice charges on borrowed funds attributable to our properties, includingfunds borrowed by our subsidiaries from us, will be deducted in computingroyalty income. The debt repayment will be scheduled to minimize any income taxpayable by ARC Resources.

 

At December31, 2009 we had an $800 million secured, extendible, financial covenant basedthree year syndicated credit facility that expires on April 15, 2011 and a $25million demand working capital facility inaddition to US $298.1 million and Cdn $29 million of senior secured notesoutstanding.  The creditfacilities and senior secured notes rank equally and contain provisions whichrestrict the ability of ARC Resources to pay Royalties and interest under theLong Term Notes to ARC and thereby may restrict distributions to Unitholders,in the event of the occurrence of certain events of default.  The credit agreement and note agreements are described under “Material Contracts” andhave been filed on SEDAR at www.sedar.com. For more information, reference is made to Note 10 of our audited consolidated financial statements for theyear ended December 31, 2009, which is incorporated by reference in this AnnualInformation Form and which has been filed on SEDAR at www.sedar.com.

 

See“Risk Factors — Risks Relating to Our Business and Operations”.

 

**OUR INFORMATION**

** **

**Trust Units**

** **

Amaximum of 650,000,000 Trust Units have been created and may be issued pursuantto the Trust Indenture.  The Trust Unitsrepresent equal undivided beneficial interests in the Trust. All Trust Unitsshare equally in all distributions made by us and all Trust Units carry equalvoting rights at meetings of Unitholders. No Unitholder will be liable to pay any further calls or assessments inrespect of the Trust Units.  Noconversion, retraction, redemption or pre-emptive rights attach to the TrustUnits.

 

**Special VotingUnit**

** **

TheTrust Indenture also provides for the issuance of special voting units whichare to be issued to a trustee and which are entitled to such number of votes atmeetings of Unitholders equal to the number of Trust Units reserved forissuance that such special voting units represent, such number of votes and anyother rights or limitations prescribed by the Board of Directors of ARCResources when the Board authorizes issuing such special voting units.

 

A SpecialVoting Unit has been designated by the Board of Directors of ARC Resources asthe Special Voting Unit, Exchangeable Shares (“**Special Voting Unit**”). The Special Voting Unit possesses a number of votes for the election ofdirectors of ARC Resources and on all other matters submitted to a vote ofUnitholders equal to the number of outstanding Exchangeable Shares from time totime not owned by Trust or ARC Subco. The holders of Trust Units and the holder of the Special Voting Unitvote together as a single class on all matters.

 

In theevent of any liquidation, dissolution or winding-up of the Trust, the holder ofthe Special Voting Unit will not be entitled to receive any of our assetsavailable for distribution to Unitholders. The holder of the Special Voting Unit will not be entitled to receivedividends.  The Special Voting Unit hasbeen issued to Computershare Trust Company of Canada, as trustee.  At such time as the Special Voting Unit hasno votes attached to it because there 

 

26

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are noExchangeable Share outstanding that are not owned by Trust or ARC Subco, theSpecial Voting Unit will be cancelled.

 

Formore information, see “Share Capital of ARC Resources — Exchangeable Shares”.

 

**TheTrust Indenture**

** **

TheTrust Indenture, among other things, provides for the calling of meetings ofUnitholders, the conduct of business thereof, notice provisions, theappointment and removal of the Trustee and the form of Trust Unitcertificates.  The Trust Indenture may beamended from time to time. Substantive amendments to the Trust Indenture,including early termination of the Trust and the sale or transfer of theproperty of the Trust as an entirety or substantially as an entirety requiresapproval by Special Resolution of Unitholders. Any approval or consent of Unitholders in relation to any matterrequired by any regulatory body will require a majority of, or such other levelof approval of Unitholders as may be stipulated by such regulatory authority,including as to the exclusion of interested or other Unitholders in thecalculation of such level of approval. See “Our Information - Meetings and Voting”.

 

Thefollowing is a summary of certain provisions of the Trust Indenture.  For a complete description of such indenture,reference should be made to the Trust Indenture, a copy of which has been filedon SEDAR at www.sedar.com, or may be obtained from the Trustee.

 

**Trustee**

** **

ComputershareTrust Company of Canada is the trustee of the Trust and also acts as thetransfer agent for the Trust Units.  TheTrustee is responsible for, among other things: (a) acceptingsubscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintainingbooks and records of the Trust and providing timely reports to holders of TrustUnits; and (c) paying distributions to Unitholders.  The Trust Indenture provides that the Trusteeshall exercise its powers and carry out its functions thereunder as Trusteehonestly, in good faith and in the best interests of the Trust and Unitholdersand, in connection therewith, shall exercise that degree of care, diligence andskill that a reasonably prudent trustee would exercise in comparablecircumstances.

 

Theterm of the Trustee’s appointment is until the next annual meeting ofUnitholders.  At each annual meeting theTrustee may be reappointed or changed as determined by a majority of the votescast at such meeting of Unitholders.  TheTrustee may resign upon 60 days’ notice to the Trust.  The Trustee may also be removed by a SpecialResolution of the Unitholders.  Suchresignation or removal becomes effective upon the acceptance or appointment ofa successor trustee.

 

ARCResources presently administers the Trust on behalf of the Trustee.  ARC Resources, on behalf of the Trustee,keeps such books and records as are necessary for the proper recording of thebusiness transactions of the Trust.

 

TheTrust Indenture provides that the Trustee shall be under no liability for anyaction or failure to act unless such liabilities arise out of the Trustee’sgross negligence, wilful default or fraud. The Trustee, where it has met its standard of care, shall be indemnifiedout of the assets of the Trust for any taxes or other government chargesimposed upon the Trustee in consequence of its performance of its duties butshall have no additional recourse against Unitholders.  In addition, the Trust Indenture containsother customary provisions limiting the liability of the Trustee.

 

**Distributionsand Allocations of Trust Income**

** **

TheTrust Indenture provides that all of the distributable income of the Trust atthe end of any calendar month including December 31 shall be declaredpayable and distributed to the Unitholders of record on the last day of eachsuch calendar month.  The distribution bythe Trust of such distributable income is enforceable by such Unitholders ofrecord.  This distributable income isallocated to Unitholders for tax purposes.

 

Inaddition, the Trust Indenture provides that such distributable income may bepaid in whole or in part by cash, in Trust Units, or promissory notes payablein whole or in part in cash or Trust Units on a specified date not more than 90days after the record date to which the promissory note relates.  The Trust Indenture also provides for the 

 

27

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consolidationof the Trust Units in the discretion of the Board of Directors of ARC Resourcesto the pre-distribution number of Trust Units after any pro-rata distributionof additional Trust Units to all Unitholders.

 

**FutureOfferings**

** **

Underthe Trust Indenture, the Trust may offer additional Trust Units or rights toacquire additional Trust Units at such times and on such terms as the Board ofDirectors of ARC Resources may determine. At the option of the Trust, the net proceeds from any offerings may beused to finance the acquisition of additional properties, make additionalcapital expenditures or to repay indebtedness incurred in connection with suchacquisitions.

 

**Meetingsand Voting**

** **

Therewill be at least one meeting of Unitholders held annually.  Special meetings of Unitholders may be calledat any time by the Trustee and shall be called by the Trustee upon the writtenrequest of Unitholders holding in aggregate not less than 20 per cent of the TrustUnits.  Notice of all meetings of Unitholdersshall be given to Unitholders at least 21 days prior to the meeting.

 

Unitholderswill be entitled at each annual meeting to appoint the Trustee, to appoint theauditors of the Trust and to elect all the members of the Board of Directors ofARC Resources.

 

**OurManagement**

** **

TheTrust Indenture provides for delegation to ARC Resources by the Trustee ofbroad discretion to administer and manage our day to day operations, whichincludes responsibility and authority to make executive decisions on behalf ofall of our direct or indirect subsidiaries and to exercise the powers of theTrustee.  Without limitation of theforegoing, ARC Resources has been specifically delegated to provide certainadministrative and support services to us, including those necessary: (i) toensure compliance with continuous disclosure obligations under applicablesecurities legislation; (ii) to provide investor relations services; (iii) toprovide or cause to be provided to Unitholders all information to whichUnitholders are entitled under the Trust Indenture; (iv) to call, hold anddistribute materials including notices of meetings and information circulars inrespect of all necessary meetings of Unitholders; (v) to determine theamounts payable from time to time to Unitholders and to arrange fordistributions to Unitholders of distributable income; and (vi) todetermine the timing and terms of future offerings of Trust Units, if any.

 

ARCResources has accepted all such delegation and has agreed that, in respect ofsuch matters, it shall carry out its functions honestly, in good faith and inour best interests and the best interests of Unitholders and, in connectiontherewith, shall exercise that degree of care, diligence and skill that areasonably prudent person would exercise in comparable circumstances.

 

**Limitationon Non-Resident Ownership**

** **

TheTrust intends to comply with the requirements under the Tax Act for “unittrusts” and “mutual fund trusts” at all relevant times such that we maintainour status of a unit trust and a mutual fund trust for purposes of the TaxAct.  In this regard, we may, from timeto time, among other things, take all necessary steps to monitor the activitiesof the Trust and ownership of the Trust Units. If at any time we become aware that the activities of the Trust andownership of the Trust Units by non-residents (non-residents of Canada andpartnerships) may threaten the status of the Trust under the Tax Act as a “unittrust” or “mutual fund trust”, we are authorized to take such action as may benecessary in the opinion of ARC Resources to maintain the status of the Trustas a unit trust and a mutual fund trust, including the imposition ofrestrictions on the issuance by the Trust, or the transfer by any Unitholder,of Trust Units to a non resident. See “Risk Factors — Risks Relating to OurStructure and Ownership of Trust Units” and “Risk Factors —Risk FactorsApplicable to Residents of the United States and Other Non-Residents ofCanada”.

 

**Rightof Redemption**

** **

TrustUnits will be redeemable at any time on demand by the holders thereof upondelivery to us of the certificate or certificates representing such TrustUnits, accompanied by a duly completed and properly executed notice requestingredemption.  Upon receipt of theredemption request, all rights to and under the Trust Units tendered for 

 

28

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redemptionshall be surrendered and the holder thereof shall be entitled to receive aprice per Unit (“**Market Redemption Price**”)equal to the lesser of: (i) 90 per cent of the market price, being theweighted average trading price of the Trust Units on the principal market onwhich the Trust Units are quoted for trading during the 10 trading day periodcommencing immediately after the date on which the Trust Units are surrenderedfor redemption; and (ii) the closing market price on the principal marketon which the Trust Units are quoted for trading on the date that the TrustUnits are surrendered for redemption.

 

Theaggregate cash Market Redemption Price payable by us in respect of any TrustUnits surrendered for redemption during any calendar month shall be satisfiedby way of a cash payment on the last day of the following month; provided thatthe entitlement of Unitholders to receive cash upon the redemption of theirTrust Units is subject to a number of conditions, including the condition thatthe total amount payable by us in respect of such Trust Units and all otherTrust Units tendered for retraction in the same calendar month must not exceed$100,000 provided that we may waive such condition in respect of any calendarmonth.

 

If aUnitholder is not entitled to receive cash upon the redemption of Trust Unitsthen we shall, at the discretion of the Board of Directors of ARC Resources,pay the Market Redemption Price by distributing either: (i) unsecuredsubordinated promissory notes bearing interest at 4.5 per cent with a 20 yearterm, or (ii) distributing a portion of some or all of the assets of ARChaving in the opinion of the Board of Directors of ARC Resources a fair marketvalue equal to the Market Redemption Price. Alternatively, the Board of Directors of ARC Resources may decide todistribute a pro rata share of the assets of the Trust, net of any liabilitiesof the Trust.

 

It isanticipated that the foregoing retraction right will not be the primarymechanism for holders of Trust Units to dispose of their Trust Units.  ARC Resources Notes which may be distributed *in specie* to Unitholders in connectionwith a redemption will not be listed on any stock exchange and no market isexpected to develop in the ARC Resources Notes. ARC Resources Notes may be subject to resale restrictions underapplicable securities laws.  ARCResources Notes so distributed may be qualified investments for trusts governedby registered retirement savings plans, registered retirement income trusts anddeferred profit sharing plans.

 

**Terminationof the Trust**

** **

Unitholdersmay vote to terminate the Trust at any meeting of Unitholders, subject to thefollowing: (a) a vote may only be held if requested in writing by theholders of not less than 20 per cent of the Trust Units; (b) a quorum of50 per cent of the issued and outstanding Trust Units is present in person orby proxy; and (c) the termination must be approved by Special Resolutionof Unitholders.

 

Unlessthe Trust is terminated or extended by vote of Unitholders earlier, the Trusteeshall commence to wind-up the affairs of the Trust on December 31, 2095.In the event that the Trust is wound-up, the Trustee will liquidate all theassets of the Trust, pay, retire, discharge or make provision for some or allobligations of the Trust and then distribute the remaining proceeds of sale toUnitholders.

 

**Reportingto Unitholders**

** **

Ourfinancial statements will be audited annually by an independent recognized firmof chartered accountants.  Our auditedfinancial statements, together with the report of such chartered accountants,will be mailed to Unitholders and the unaudited interim financial statements ofthe Trust will be mailed to Unitholders as prescribed by securitieslegislation.  Our year end is December 31.  We are subject to the continuous disclosureobligations under all applicable securities legislation.

 

Unitholdersare entitled to inspect, during normal business hours, at the offices of theTrustee, and, upon payment of reasonable reproduction costs, to receivephotocopies of certain material contracts, the Trust Indenture and a listing ofthe registered holders of Trust Units.

 

**DistributionReinvestment and Optional Trust Unit Purchase Plan**

** **

A planhas been established to provide Unitholders who are residents of Canada (withinthe meaning of the *Tax Act*) witha method to reinvest distributions by purchasing additional Trust Units.

 

29

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**CORPORATE GOVERNANCE**

** **

**General**

** **

Ingeneral, ARC Resources has been delegated substantially all of our managementdecisions.  Unitholders are entitled toelect all of the Board of Directors of ARC Resources pursuant to the terms ofthe Trust Indenture.  The Articles of ARCResources were amended on March 20, 2008 to provide that the Board ofDirectors of ARC Resources shall consist of a minimum of three and a maximum of12 directors.

 

**TrustIndenture**

** **

Pursuantto the Trust Indenture, Unitholders are entitled to direct the manner in whichwe will vote our shares in ARC Resources at all meetings in respect of matters,relating to the election of the directors of ARC Resources, approving itsfinancial statements and appointing auditors of ARC Resources who shall be thesame as our auditors.  Prior toexercising our voting rights in ARC Resources, each Unitholder is entitled tovote on the basis of one vote per Trust Unit held, and we are required to voteour shares in ARC Resources in accordance with the result of the vote ofUnitholders.

 

**DecisionMaking**

** **

TheBoard of Directors of ARC Resources has a mandate to supervise the managementof our business and affairs and to act with a view to our best interests.  The Board of Directors of ARC Resources supervisesthe management of the business and affairs of our subsidiaries.  The Board of Directors’ mandate includes: (a) theresponsibility for managing our affairs; (b) monitoring our management andour activities; (c) reviewing strategic operating, capital and financialplans; and (d) compliance reporting and corporate communications.  In particular, significant operationaldecisions and all decisions relating to: (i) the acquisition anddisposition of properties for a purchase price or proceeds in excess of anamount prescribed from time to time by the Board of Directors; (ii) theapproval of capital expenditure budgets; and (iii) establishment of creditfacilities are made by the Board of Directors of ARC Resources.  In addition, the Trustee has delegated broaddiscretion in relation to our day to day operations to the Board of Directorsof ARC Resources including all decisions relating to:  (i) matters relating to any offers forTrust Units; (ii) issuances of additional Trust Units; and (iii) thedetermination of the amount of distributable income.  Any amendment to the royalty agreementsrequires the approval of the Board of Directors of ARC Resources on ourbehalf.  The Board of Directors of ARCResources holds regularly scheduled meetings at least quarterly to review thebusiness and affairs of our subsidiaries and make any necessary decisionsrelating thereto.

 

TheTrust Indenture gives to the Board of Directors of ARC Resources the authorityto exercise the rights, powers and privileges for all matters relating to themaximization of Unitholder value in the context of an offer including anyUnitholder rights protection plan, any defensive action to an offer, anydirectors circular in response to an offer, any regulatory or court proceedingrelating to an offer and any related or ancillary matter.

 

**Boardof Directors of ARC Resources**

** **

ARCResources has a Board of Directors consisting of nine individuals, all of whomhave been elected by Unitholders, except for Kathleen M. O’Neill who joined theBoard on June 1, 2009, including by the holders of the Exchangeable Sharesthrough the Special Voting Unit.

 

Thename, municipality of residence, position held and principal occupation of eachdirector and officer of ARC Resources as at December 31, 2009 are set outbelow:

 
| **Name and  Municipality of Residence**                      | ** ** | **Offices Held  and Time as Director**                     | ** ** | **Principal Occupation**                                                     |
|--------------------------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------------------------------------|
| ** **                                                   | ** ** | ** **                                                 | ** ** | ** **                                                                   |
| Mac H. Van Wielingen(3)(4)(5)  Calgary, Alberta, Canada |       | Chairman of the Board and Director since  May 3, 1996 |       | Co-Chairman of ARC Financial Corporation (an  investment management company) |
|                                                         |       |                                                       |       |                                                                         |
| Walter DeBoni(1) (3) (5)  Calgary, Alberta, Canada |       | Vice Chairman and Director since June 26,  1996       |       | Independent Businessman                                                      |

 

30

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| **Name and  Municipality of Residence**                               | ** ** | **Offices Held  and Time as Director**                       | ** ** | **Principal Occupation**                                                                         |
|-----------------------------------------------------------------------|------------|--------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|
| ** **                                                            | ** ** | ** **                                                   | ** ** | ** **                                                                                       |
| John P. Dielwart  Calgary, Alberta, Canada                            |       | Chief Executive Officer and Director since  May 3, 1996 |       | Chief Executive Officer of ARC Resources                                                         |
|                                                                  |       |                                                         |       |                                                                                             |
| Fred J. Dyment(1)(2)(3)  Calgary, Alberta, Canada                     |       | Director since April 17, 2003                           |       | Independent Businessman                                                                          |
|                                                                  |       |                                                         |       |                                                                                             |
| James C. Houck(1)(2)(6)  Calgary, Alberta, Canada                     |       | Director since February 14, 2008                        |       | President and Chief Executive Officer of The  Churchill Corporation                              |
|                                                                  |       |                                                         |       |                                                                                             |
| Michael M. Kanovsky(2)(3)(5)  Calgary, Alberta, Canada                |       | Director since May 3, 1996                              |       | Independent Businessman                                                                          |
|                                                                  |       |                                                         |       |                                                                                             |
| Harold N. Kvisle(6)  Calgary, Alberta Canada                          |       | Director since May 20, 2009                             |       | President and Chief Executive Officer of  TransCanada Corporation and TransCanada Pipelines Ltd. |
|                                                                  |       |                                                         |       |                                                                                             |
| Kathleen M. O’Neill (1)(4)  Toronto, Ontario, Canada             |       | Director since June 1, 2009                             |       | Independent Businesswoman                                                                        |
|                                                                  |       |                                                         |       |                                                                                             |
| Herbert C. Pinder, Jr.(4)(5)(6)  Saskatoon, Saskatchewan, Canada |       | Director since January 1, 2006                          |       | Independent Businessman                                                                          |
|                                                                  |       |                                                         |       |                                                                                             |
| Myron M. Stadnyk  Calgary, Alberta, Canada                            |       | President and Chief Operating Officer                        |       | President and Chief Operating Officer of ARC  Resources                                          |
|                                                                  |       |                                                         |       |                                                                                             |
| Doug J. Bonner  Calgary, Alberta, Canada                              |       | Senior Vice-President, Corporate Development                 |       | Senior Vice-President, Corporate Development of  ARC Resources                                   |
|                                                                  |       |                                                         |       |                                                                                             |
| David P. Carey  Calgary, Alberta, Canada                              |       | Senior Vice-President, Capital Markets                       |       | Senior Vice-President, Capital Markets of ARC  Resources                                         |
|                                                                  |       |                                                         |       |                                                                                             |
| Terry Gill  Calgary, Alberta, Canada                                  |       | Senior Vice-President, Corporate Services                    |       | Senior Vice-President, Corporate Services of ARC  Resources                                      |
|                                                                  |       |                                                         |       |                                                                                             |
| Steven W. Sinclair

Calgary, Alberta, Canada                          |       | Senior Vice-President, Finance and Chief Financial  Officer  |       | Senior Vice-President, Finance and Chief Financial  Officer of ARC Resources                     |
|                                                                  |       |                                                         |       |                                                                                             |
| Terry M. Anderson  Calgary, Alberta, Canada                           |       | Vice-President, Operations                                   |       | Vice-President, Operations of ARC Resources                                                      |
|                                                                  |       |                                                         |       |                                                                                             |
| Ingram B. Gillmore  Calgary, Alberta, Canada                          |       | Vice-President, Engineering                                  |       | Vice-President, Engineering of ARC Resources                                                     |
|                                                                  |       |                                                         |       |                                                                                             |
| Neil Groeneveld  Calgary, Alberta, Canada                             |       | Vice-President, Geosciences                                  |       | Vice-President, Geosciences of ARC Resources                                                     |
|                                                                  |       |                                                         |       |                                                                                             |
| P. Van R. Dafoe  Calgary, Alberta, Canada                             |       | Vice-President and Treasurer                                 |       | Vice-President and Treasurer of ARC Resources                                                    |
|                                                                  |       |                                                         |       |                                                                                             |
| Allan R. Twa  Calgary, Alberta, Canada                                |       | Secretary                                                    |       | Partner, Burnet, Duckworth &  Palmer LLP (barristers and solicitors)               |

 

----

Notes:
| (1) | Member of Audit Committee in 2009.                             |
|-----|----------------------------------------------------------------|
| (2) | Member of Reserves Committee in 2009.                          |
| (3) | Member of Risk Committee in 2009.                              |
| (4) | Member  of Human Resources and Compensation Committee in 2009. |

 

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| (5) | Member  of Policy and Board Governance Committee in 2009.    |
|-----|--------------------------------------------------------------|
| (6) | Member  of Health, Safety and Environment Committee in 2009. |

 

Withthe exception of the following individuals, the officers and directors haveheld the position set forth as their principal occupation for the last fiveyears: Prior to October 2007, Mr. James Houck was President and ChiefExecutive Officer and a director of Western Oil Sands Ltd. and prior to April,2005, Mr. Houck held several senior positions with Chevron TexacoInc.  Prior to November 2005, StevenW. Sinclair was Vice-President, Finance and Chief Financial Officer, David P.Carey was Vice-President, Business Development, Doug Bonner was Vice-President,Engineering and Myron J. Stadnyk, was Vice-President, Operations and Land andprior to February 2009 was Senior Vice-President of ARC Resources.  Prior to July 2007 P. Van R. Dafoe wasTreasurer of ARC Resources.  Prior to November 2005,Terry M. Anderson was Manager, Field Operations of ARC Resources.  Prior to January 2007, Ingram Gillmorewas Engineering Manager of ARC Resources. Prior to September 2008, Terry Gill was Senior Vice President HumanResources at Superior Propane.  Prior to October 2008,Neil Groeneveld was Manager, Geology of ARC Resources.  Prior to February 2009 John P. Dielwartwas President of ARC Resources.

 

Thefollowing comprises a brief description of the background of the officers ofARC Resources.

 

***John P. Dielwart, B.Sc., P.Eng.***

*** ***

Mr. Dielwartis the Chief Executive Officer of ARC Resources Ltd. and has overall managementresponsibility for the Trust. Prior to joining ARC in 1996, Mr. Dielwartspent 12 years with a major Calgary based oil and natural gas engineeringconsulting firm, as senior vice-president and a director, where he gainedextensive technical knowledge of oil and natural gas properties in westernCanada. He began his career working for five years with a major oil and naturalgas company in Calgary. Mr. Dielwart is a Past-Chairman of the Board ofGovernors for the Canadian Association of Petroleum Producers (CAPP). He holdsa Bachelor of Science with Distinction (Civil Engineering) degree, Universityof Calgary. He has also been a director of ARC since 1996.

 

***Steven W. Sinclair, B. Comm., CA***

*** ***

Mr. Sinclairis Senior Vice-President Finance and Chief Financial Officer of ARC ResourcesLtd. and oversees all of the financial and accounting affairs of ARC EnergyTrust. Mr. Sinclair has a Bachelor of Commerce from the University ofCalgary, and a Chartered Accountant’s designation which he received in 1981. Hehas over 25 years experience within the finance, accounting and taxation areasof the oil and gas industry and has been with the Trust since 1996. Mr. Sinclairis also a member of the Alberta and Canadian Institutes of CharteredAccountants.

 

***Myron M. Stadnyk, P.Eng.***

*** ***

Mr. Stadnykis the President and Chief Operating Officer of ARC Resources Ltd. and isresponsible for all aspects of ARC’s ongoing operational and productionmanagement and strategies. He has over 25 years experience in the oil and gasbusiness. Prior to joining ARC Resources Ltd. in 1997, Mr. Stadnyk workedwith a major oil and gas company in both domestic and international operations.He has a B.Sc. in Mechanical Engineering from the University of Saskatchewanand is a member of the Association of Professional Engineers.

 

***Doug J. Bonner, P.Eng.***

*** ***

Mr. Bonneris Senior Vice-President, Corporate Development of ARC Resources Ltd. and isresponsible for the strategic development of ARC’s enhanced oil recoveryassets. He holds a B.Sc. in Geological Engineering from the University ofManitoba. Mr. Bonner’s major area of expertise is reservoir engineeringand he has extensive technical knowledge of oil and natural gas fieldsthroughout western Canada, the east coast and northern Canada. Prior to joiningARC in 1996, Mr. Bonner spent 18 years with various major oil and naturalgas companies in positions of increasing responsibility.

 

***David P. Carey, P.Eng., MBA***

*** ***

Mr. Careyis Senior Vice-President, Capital Markets of ARC Resources Ltd. and isresponsible for all facets of investor relations and corporate governance. Heholds both a B.Sc. in Geological Engineering and a MBA from Queen’s University.Mr. Carey brings over 25 years of diverse experience in the Canadian andInternational energy industries covering exploration, production and projectevaluations in western Canada, oil sands, the Canadian 

 

32

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frontiersand internationally. Prior to joining ARC Resources in 2001, Mr. Careyheld senior positions with Athabasca Oil Sands Trust and a major Canadian oiland gas company.

 

***Terry Gill, B.PE.***

*** ***

Mr. Gillis Senior Vice-President, Corporate Services of ARC Resources Ltd. and overseesall human resources, information technology and office services relatedactivities. Prior to joining ARC in September 2007, Mr. Gill spenteight years with a major national distribution company as a senior executive. Healso spent 15 years in the oil and gas industry and has broad experience in allareas of talent management. Mr. Gill has coached high performance athletesat an elite level and holds a B.PE. in coaching leadership from the Universityof Alberta.

 

***Terry M. Anderson, P.Eng.***

*** ***

Mr. Andersonis Vice-President, Operations of ARC Resources Ltd. and is responsible for allof ARC’s operational activities. He has a B.Sc. in Petroleum Engineering and isa member of the Association of Professional Engineers in Alberta, Saskatchewanand British Columbia. Mr. Anderson has over 15 years of experience indrilling, completion, pipeline, facility and production operations.  Prior to joining ARC in 2000, he worked at amajor oil and gas company.

 

***Ingram B. Gillmore,P.Eng.***

*** ***

Mr. Gillmoreis Vice-President, Engineering of ARC Resources Ltd. and is responsible for allof ARC’s engineering and joint venture related activities. He holds a B.Sc. inChemical engineering from the University of Waterloo (1991) and a Bachelor ofFine Arts. Mr. Gillmore has been at ARC since 2002. Prior to joining ARC, Mr. Gillmoreheld positions with several major oil and gas companies.

 

***Neil Groeneveld, P. Geol.***

*** ***

Mr. Groeneveldis ****Vice-President,Geosciences**** of ARC Resources Ltd. and is responsiblefor ARC’s geophysical and geological activities. He has over 20 years ofexperience in the western Canadian oil & gas business and brings abroad background in oil and gas development, exploration and operations. Heholds a Master of Science degree in Geology from the University of Regina.Prior to joining ARC in 2003, Mr. Groeneveld held senior positions withlarge and intermediate oil and gas companies.

 

***P. Van R. Dafoe, B.Comm., CMA***

*** ***

Mr. Dafoeis Vice-President and Treasurer of ARC Resources Ltd. and is responsible forall of ARC’s Hedging and Treasury related activities. He has a Bachelor ofCommerce — Honours from the University of Manitoba and obtained his CertifiedManagement Accountant’s designation in 1995. Mr. Dafoe joined ARC in 1999after 13 years with various companies in the finance and accounting area of theoil and gas industry.

 

***Allan R. Twa, Q.C.***

*** ***

Mr. Twaacts as Corporate Secretary of ARC Resources Ltd. A member of the Alberta Barsince 1971, Mr. Twa is a partner in the law firm Burnet, Duckworth &Palmer LLP. Mr. Twa holds a B.A. (Political Science) from the Universityof Calgary, a LL.B. from the University of Alberta and a LL.M. from theUniversity of London, England. Over the last 30 years, Mr. Twa has beenengaged in a legal practice involving legal administration of public companiesand trusts, corporate finance, and mergers and acquisitions.

 

Mac VanWielingen is the Chairman and a Director of ARC Resources and was a director ofGauntlet Energy Corporation which secured creditor protection pursuant to the *Companies’ Creditors Arrangement Act* on June 17,2003 and was subsequently acquired by Ketch Resources Ltd. in December, 2003.

 

All ofthe directors of ARC Resources were elected on May 20, 2009, exceptKathleen O’Neill who was appointed as an addition to the Board of Directors on June 1,2009, to hold office until the next annual general meeting of ARC Resources,which is scheduled for May 18, 2010. As at December 31, 2009, the directors and officers of ARCResources, as a group, beneficially owned, or controlled or directed, directlyor indirectly, 1,083,218 Trust Units or 

 

33

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approximately0.46 per cent of the outstandingTrust Units, and 441,466 Exchangeable Shares or approximately 51 per cent ofthe outstanding Exchangeable Shares.  Ifall of the Exchangeable Shares had been exchanged for Trust Units at theExchange Ratio in effect on December 31, 2009, the directors and officersof ARC Resources as a group would hold 2,283,798 Trust Units or approximately0.96 per cent of the outstanding Trust Units as at December 31, 2009.

 

**AUDIT COMMITTEE DISCLOSURES**

** **

MultilateralInstrument 52-110 (“**MI 52-110**”)relating to audit committees has mandated certain disclosures for inclusion inthis Annual Information Form.  The textof the Audit Committee’s mandate is attached as Appendix C to this AnnualInformation Form.

 

**Membersof the Audit Committee**

** **

As of December 31,2009, the members of the Audit Committee were Fred J. Dyment, chairman, andWalter DeBoni, James C. Houck and Kathleen O’Neill, each of whom is independentand financially literate within the meaning of MI 52-110.  The following comprises a brief summary ofeach member’s education and experience:

 

***Fred J. Dyment***

*** ***

Mr. Dymenthas over 30 years experience in the oil and gas business and is currently anindependent businessman. His past business career included positions asPresident and CEO for Maxx Petroleum and President and CEO of Ranger OilLimited. Mr. Dyment received a Chartered Accountant designation from theprovince of Ontario in 1972. Mr. Dyment currently sits as a Director onthe Boards of Tesco Corporation, Transglobe Energy Corporation andWesternZagros Resources Ltd.  He has beena Director of ARC since 2003.

 

***Walter DeBoni***

*** ***

Mr. DeBoniretired from Husky Energy Inc. where he held the position of VP, CanadaFrontier & International Business. Prior to this Mr. DeBoni wasCEO of Bow Valley Energy for a number of years. In addition to his time atHusky and Bow Valley he has also held numerous top executive posts in the oiland gas industry with major corporations. Mr. DeBoni holds a B.A.Sc. Chem.Eng. from the University of British Columbia, a MBA degree with a major inFinance from the University of Calgary and is a member of the association ofProfessional Engineers, Geologists and Geophysicists of Alberta. He is a pastChairman of the Petroleum Society of CIM, a past Director of the Society ofPetroleum Engineers and has been a Director of ARC Resources since 1996.

 

***James C. Houck***

*** ***

Mr. JamesC. Houck is currently the President and Chief Executive Officer and a directorof The Churchill Corporation.  Prior to January 2009Mr. Houck was an independent businessman and prior to October 18,2007 was the President and Chief Executive Officer and a director of WesternOil Sands Ltd.  Mr. Houck has a B.Sc. fromTrinity University and a MBA from the University of Houston.  Mr. Houck has over 40 years of industryexperience, primarily with Chevron Texaco Inc. where he held a number of seniormanagement positions.

 

***Kathleen M. O’Neill***

*** ***

Ms. O’Neill is a corporate director andhas extensive experience in accounting and financial services.  Prior to 2005, she was an ExecutiveVice-President of BMO Financial Group with accountability for a number of majorbusiness units.  Prior to joining BMOFinancial Group in 1994, she was a partner with PricewaterhouseCoopers.  Ms. O’Neill is an FCA (Fellow ofInstitute of Chartered Accountants) and has her ICD.D designation from theInstitute of Corporate Directors.  Ms. O’Neillcurrently serves on the board of directors of Finning International Inc., whichis the world’s largest Caterpillar dealer; Invesco Trimark Funds and the TMXGroup Inc., which operates cash and derivative markets (including the TSX, TSXVenture Exchange, NGX, and the Montreal Exchange), clearing facilities and dataservices.  Ms. O’Neill is Chair ofSt. Joseph’s Health Centre Foundation.

 

34

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**PrincipalAccountant Fees and Services**

** **

TheAudit Committee has not adopted specific policies and procedures for theengagement of non-audit services and pre-approves each such engagement or typeof engagement for every fiscal year.

 

Ourexternal auditor is Deloitte & Touche LLP.  The following is a summary of the externalaudit services fees by category.

 

***Audit Fees***

*** ***

Theaggregate fees billed by our external auditor for audit services are:

 
| 2009 |   | $ | 733,250 |   |
|------|--------|---|---------|--------|
| 2008 |   | $ | 677,834 |   |

 

 

***Audit Related Fees***

*** ***

Theaggregate fees billed by our external auditor for assurance and relatedservices that are reasonably related to the performance of the audit or reviewof the financial statements (not included in audit services fees) are:

 
| 2009 |   | $ | 63,095 |   |
|------|--------|---|--------|--------|
| 2008 |   | $ | 36,199 |   |

 

***Tax Fees***

*** ***

Theaggregate fees billed by our external auditor for professional services formunicipal property tax compliance, tax advice and tax planning are:

 
| 2009 |   | $ | Nil     |   |
|------|--------|---|---------|--------|
| 2008 |   | $ | 114,013 |   |

 

***All Other Fees***

*** ***

Theaggregate fees billed by our external auditor for products and services notincluded under the headings:  Audit Fees,Audit Related Fees, Tax Fees and All Other Fees.

 
| 2009 |   | $ | Nil |   |
|------|--------|---|-----|--------|
| 2008 |   | $ | Nil |   |

 

**CONFLICTS OF INTEREST**

** **

TheBoard of Directors has adopted a Code of Business Conduct and Ethics and a Codeof Ethics for Senior Financial Officers (the “**Codes**”).  In general, the private investment activitiesof employees, directors and officers are not prohibited, however, should anexisting investment pose a potential conflict of interest the potentialconflict is required by the Codes to be disclosed to the President, ChiefExecutive Officer or the Board of Directors. Any other activities of employees which pose a potential conflict ofinterest are also required by the Codes to be disclosed to the President, ChiefExecutive Officer or the Board of Directors. Any such potential conflicts of interests will be dealt with openly withfull disclosure of the nature and extent of the potential conflicts ofinterests with the Trust.

 

It isacknowledged in the Codes that employees, officers and directors may be directorsor officers of other entities engaged in the oil and gas business, and thatsuch entities may compete directly or indirectly with the Trust.  No assurance can be given that opportunitiesidentified by directors of ARC Resources will be provided to us.  Passive investments in public or privateentities of less than one per cent of the outstanding shares will not be viewedas “competing” with the Trust.  Anydirector, officer or employee of ARC Resources which is a director or officerof any entity engaged in the oil and gas business shall disclose suchoccurrence to the Board of Directors. Any director, officer or employee of ARC Resources who is activelyengaged in the management of, or who owns an 

 

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investmentof one per cent or more of the outstanding shares, in public or privateentities shall disclose such holding to the Board of Directors.  In the event that any circumstance shouldarise as a result of such positions or investments being held or otherwisewhich in the opinion of the Board of Directors constitutes a conflict ofinterest which reasonably affects such person’s ability to act with a view tothe best interests of the Trust, the Board of Directors will take such actionsas are reasonably required to resolve such matters with a view to the bestinterests of the Trust.  Such actions,without limitation, may include excluding such directors, officers or employeesfrom certain information or activities of the Trust.

 

The *Business Corporations Act* (Alberta)provides that in the event that an officer or director is a party to, or is adirector or an officer of or has a material interest in any person who is aparty to, a material contract or material transaction or proposed materialcontract or proposed material transaction, such officer or director shalldisclose the nature and extent of his or her interest and shall refrain fromvoting to approve such contract or transaction.

 

**INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

** **

Thereis no material interest, direct or indirect, of any director or senior officer,or to our knowledge any person or company that is the direct or beneficialowner, or who exercises control or direction over more than 10 per cent ofoutstanding Trust Units, or any associate or affiliate of any of the foregoing,in any transaction within the three most recently completed financial years orduring the current financial year that has materially affected or is reasonablyexpected to affect the Trust.

 

**DISTRIBUTIONS TO UNITHOLDERS**

** **

Thefollowing per Trust Unit distributions have been made in the last threecompleted financial years:

 
| **2007**       |   |   |   |
|----------------|--------|--------|--------|
| First Quarter  |   | $      | 0.60   |   |
| Second Quarter |   | $      | 0.60   |   |
| Third Quarter  |   | $      | 0.60   |   |
| Fourth Quarter |   | $      | 0.60   |   |
|           |   |   |   |
| **2008**       |   |   |   |
| First Quarter  |   | $      | 0.60   |   |
| Second Quarter |   | $      | 0.68   |   |
| Third Quarter  |   | $      | 0.80   |   |
| Fourth Quarter |   | $      | 0.59   |   |
|           |   |   |   |
| **2009**       |   |   |   |
| First Quarter  |   | $      | 0.36   |   |
| Second Quarter |   | $      | 0.32   |   |
| Third Quarter  |   | $      | 0.30   |   |
| Fourth Quarter |   | $      | 0.30   |   |

 

Incertain circumstances, distributions may be restricted by our borrowingagreements.  For more information see “Other Information Relating to Our Business —Borrowing”.  Distributions paid toUnitholders in 2007 were three per cent tax deferred, 2008 distributions weretwo per cent tax deferred and 2009 distributions were three per cent taxdeferred.  For more information, see “OurBusiness —Distributions and Distribution Policy”.

 

**PRICE RANGE AND TRADING VOLUME OF TRUST UNITSAND EXCHANGEABLE SHARES**

** **

TheTrust Units are listed and posted for trading on the TSX.  The trading symbol for the Trust Units isAET.UN.  The following table sets forththe high and low closing prices and the aggregate volume of trading of theTrust Units on the TSX for the periods indicated (as quoted by the TSX):

 

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| ** **      | ** ** | **Toronto Stock Exchange** | ** ** |
|-----------------|------------|----------------------------|------------|
| **2009 Period** | ** ** | **High**                   | ** ** | **Low** | ** ** | **Volume** | ** ** |
| ** **      | ** ** | **$**                      | ** ** | **$** | ** ** | ** ** | ** ** |
| January         |       | 21.48                      |       | 16.07 |   | 22,123,293 |   |
| February        |       | 16.70                      |       | 12.46 |   | 24,297,428 |   |
| March           |       | 15.95                      |       | 11.41 |   | 27,362,678 |   |
| April           |       | 16.19                      |       | 13.66 |   | 15,541,209 |   |
| May             |       | 17.82                      |       | 15.52 |   | 21,227,035 |   |
| June            |       | 19.55                      |       | 16.26 |   | 22,704,115 |   |
| July            |       | 17.79                      |       | 15.16 |   | 17,962,304 |   |
| August          |       | 18.38                      |       | 17.08 |   | 16,005,250 |   |
| September       |       | 20.20                      |       | 15.92 |   | 20,664,113 |   |
| October         |       | 22.10                      |       | 18.15 |   | 22,501,148 |   |
| November        |       | 21.47                      |       | 18.92 |   | 15,112,772 |   |
| December        |       | 20.65                      |       | 18.78 |   | 15,236,851 |   |

 

TheExchangeable Shares are listed and posted for trading on the TSX.  The trading symbol for the ExchangeableShares is ARX.  The following table setsforth the high and low closing prices and the aggregate volume of trading ofthe Exchangeable Shares on the TSX for the periods indicated (as quoted by theTSX):

 
| ** **      | ** ** | **Toronto Stock Exchange** | ** ** |
|-----------------|------------|----------------------------|------------|
| **2009 Period** | ** ** | **High**                   | ** ** | **Low** | ** ** | **Volume** | ** ** |
| ** **      | ** ** | **$**                      | ** ** | **$** | ** ** | ** ** | ** ** |
| January         |       | 51.00                      |       | 42.85 |   | 420 |   |
| February        |       | 41.50                      |       | 35.35 |   | 1,900 |   |
| March           |       | 46.98                      |       | 30.39 |   | 5,012 |   |
| April           |       | 41.98                      |       | 33.03 |   | 190 |   |
| May             |       | 44.24                      |       | 37.50 |   | 1,700 |   |
| June            |       | 51.50                      |       | 37.00 |   | 1,970 |   |
| July            |       | 44.70                      |       | 40.01 |   | 2,266 |   |
| August          |       | N/A                        |       | N/A |   | 0 |   |
| September       |       | 54.00                      |       | 48.99 |   | 15,400 |   |
| October         |       | 57.00                      |       | 53.00 |   | 18,000 |   |
| November        |       | 57.50                      |       | 53.00 |   | 30,728 |   |
| December        |       | 56.00                      |       | 52.00 |   | 6,222 |   |

 

**INDUSTRY REGULATIONS**

** **

Companies operating in the oil and natural gasindustry are subject to extensive regulation and control of operations(including land tenure, exploration, development, production, natural gasprocessing, refining, transportation, and marketing) as a result of legislationenacted by various levels of government and with respect to the pricing andtaxation of oil and natural gas through agreements among the governments ofCanada, Alberta, British Columbia and Saskatchewan, all of which should becarefully considered by investors in the oil and gas industry.  It is not expected that any of theseregulations or controls will affect the Corporation’s operations in a mannermaterially different than they will affect other oil and natural gas companiesof similar size.  All current legislationis a matter of public record and the Corporation is unable to predict whatadditional legislation or amendments may be enacted.  Outlined below are some of the principalaspects of legislation, regulations and agreements governing the oil and gas industry.

 

**Pricingand Marketing**

** **

***Oil***

 

The producers of oil are entitled to negotiate salescontracts directly with oil purchasers, with the result that the marketdetermines the price of oil.  Oil pricesare primarily based on worldwide supply and demand.  The specific price depends in part on oilquality, prices of competing fuels, distance to market, the value of refinedproducts, the supply/demand balance, and contractual terms of sale.  Oil exporters are also entitled to enter intoexport contracts 

 

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with terms not exceeding one year in the case oflight crude oil and two years in the case of heavy crude oil, provided that anorder approving such export has been obtained from the National Energy Board ofCanada (the “**NEB**”).  Any oil export to be made pursuant to acontract of longer duration (to a maximum of 25 years) requires an exporter toobtain an export licence from the NEB and the issuance of such a licencerequires a public hearing and the approval of the Governor in Council.

 

***Natural Gas***

 

The pricing of the vast majority of natural gassales in western Canada is determined through the price discovery process inthe liquid market established at the Nit Hub located in Alberta.  Natural gas exported from Canada is subjectto regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices andother terms with purchasers, provided that the export contracts must continueto meet certain other criteria prescribed by the NEB and the Government ofCanada.  Natural gas (other than propane,butane and ethane) exports for a term of less than two years or for a term oftwo to 20 years (in quantities of not more than 30,000 m3/day) must bemade pursuant to an NEB order.  Anynatural gas export to be made pursuant to a contract of longer duration (to amaximum of 25 years) or for a larger quantity requires an exporter to obtain anexport licence from the NEB and the issuance of such a licence requires apublic hearing and the approval of the Governor in Council.

 

The governments of Alberta, British Columbia andSaskatchewan also regulate the volume of natural gas that may be removed fromthose provinces for consumption elsewhere based on such factors as reserveavailability, transportation arrangements, and market considerations.

 

**PipelineCapacity**

** **

As a result of pipeline expansions over the pastseveral years, there is ample pipeline capacity to accommodate currentproduction of oil and natural gas in western Canada and pipeline capacity doesnot limit the ability to produce and to market oil and natural gas production.

 

**TheNorth American Free Trade Agreement**

** **

The North American Free Trade Agreement (“**NAFTA**”) among the governments of Canada,the United States and Mexico became effective on January 1, 1994.  NAFTA carries forward most of the materialenergy terms that are contained in the Canada United States Free TradeAgreement.  In the context of energyresources, Canada continues to remain free to determine whether exports ofenergy resources to the United States or Mexico will be allowed, provided thatany export restrictions do not: (i) reduce the proportion of energyresources exported relative to domestic use (based upon the proportionprevailing in the most recent 36 month period); (ii) impose an exportprice higher than the domestic price (subject to an exception with respect tocertain voluntary measures which only restrict the volume of exports); and (iii) disruptnormal channels of supply.  All threesignatory countries are prohibited from imposing minimum or maximum export orimport price requirements, provided, in the case of export price requirements,that any prohibition in any circumstances in which any other form ofquantitative restriction is applied is prohibited, and in the case ofimport-price requirements, that such requirements do not apply with respect toenforcement of countervailing and anti-dumping orders and undertakings.

 

NAFTA contemplates the reduction of Mexicanrestrictive trade practices in the energy sector by 2010 and prohibitsdiscriminatory border restrictions and export taxes.  NAFTA also contemplates clearer disciplineson regulators to ensure fair implementation of any regulatory changes, minimizedisruption of contractual arrangements and avoid undue interference withpricing, marketing and distribution arrangements, all of which are importantfor Canadian oil and natural gas exports.

 

**Royaltiesand Incentives**

** **

***General***

*** ***

In addition to federal regulation, each province haslegislation and regulations which govern royalties, production rates and othermatters.  The royalty regime in a givenprovince is a significant factor in the profitability of crude oil, natural gasliquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiation between the mineral freehold owner and the lessee,although production 

 

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from such lands is subject to certain provincialtaxes and royalties.  Royalties fromproduction on Crown lands are determined by governmental regulation and aregenerally calculated as a percentage of the value of gross production.  The rate of royalties payable generallydepends in part on prescribed reference prices, well productivity, geographicallocation, field discovery date, method of recovery and the type or quality ofthe petroleum product produced.  Otherroyalties and royalty-like interests are, from time to time, carved out of theworking interest owner’s interest through non-public transactions.  These are often referred to as overridingroyalties, gross overriding royalties, net profits interests, or net carriedinterests.

 

Occasionally the governments of the western Canadianprovinces create incentive programs for exploration and development.  Such programs often provide for royalty ratereductions, royalty holidays or royalty tax credits and are generallyintroduced when commodity prices are low to encourage exploration and developmentactivity by improving earnings and cash flow within the industry.

 

***Alberta***

*** ***

Producers of oil and natural gas from Crown lands inAlberta are required to pay annual rental payments, currently at a rate of$3.50 per hectare, and make monthly royalty payments in respect of oil andnatural gas produced.

 

On October 25, 2007, the Government of Albertareleased a report entitled “The New Royalty Framework” (“**NRF**”) containing the Government’s proposalsfor Alberta’s new royalty regime which were subsequently implemented by the *Mines and Minerals (New Royalty Framework) Amendment Act, 2008*.  The NRF took effect on January 1, 2009.

 

On March 11, 2010, the Government of Albertaannounced changes to Alberta’s royalty system intended to increase Alberta’scompetitiveness in the upstream oil and natural gas sectors; specifically, themaximum royalty rates for conventional oil and natural gas production will bedecreased effective for the January 2011 production month and certaintemporary incentive programs currently in place will be made permanent.  Further details with respect to the changesto Alberta’s royalty system are expected to be provided in the coming months.

 

With respect to conventional oil, the NRF eliminatedthe classification system used by the previous royalty structure which classifiedoil based on the date of discovery of the pool. Under the NRF, royalty rates for conventional oil are set by a singlesliding rate formula which is applied monthly and incorporates separatevariables to account for production rates and market prices.  Royalty rates for conventional oil under theNRF range from 0-50 per cent, an increase from the previous maximum rates of30-35 per cent depending on the vintage of the oil, and rate caps are set at$120 per barrel.  Effective January 1,2011, the maximum royalty payable under the NRF will be reduced to 40 per cent.

 

Royalty rates for natural gas under the NRF aresimilarly determined using a single sliding rate formula incorporating separatevariables to account for production rates and market prices.  Royalty rates for natural gas under the NRFrange from 5-50 per cent, an increase from the previous maximum rates of 5-35per cent, and rate caps are set at $17.75/GJ. Effective January 1, 2011, the maximum royalty payable under theNRF will be reduced to 36 per cent.

 

Oil sands projects are also subject to the NRF.  Prior to payout, the royalty is payable ongross revenues of an oil sands project. Gross revenue royalty ratesrange between 1-9 per cent depending on the market price of oil: rates are oneper cent when the market price of oil is less than or equal to $55 per barreland increase for every dollar of market price of oil increase to a maximum ofnine per cent when oil is priced at $120 or higher.  After payout, the royalty payable is thegreater of the gross revenue royalty based on the gross revenue royalty rate of1-9 per cent and the net revenue royalty based on the net revenue royaltyrate.  Net revenue royalty rates start at25 per cent and increase for every dollar of market price of oil increase above$55 up to 40 per cent when oil is priced at $120 or higher.  An oil sands project reaches payout when itscumulative revenue exceeds its cumulative costs.  Costs include specified allowed capital andoperating costs related to the project plus a specified return allowance.  As part of the implementation of the NRF, theGovernment of Alberta renegotiated existing contracts with certain oil sandsproducers that were not compatible with the NRF.

 

In August 2006, the Government of Albertaintroduced the Innovative Energy Technologies Program (the “**IETP**”), which has a stated objective ofpromoting producers’ investment in research, technology and innovation for thepurposes of improving environmental performance while creating commercialvalue.  The IETP is backed by a $200 

 

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million funding commitment over a five-year periodbeginning April 1, 2005 and provides royalty adjustments to specific pilotand demonstration projects that utilize innovative technologies to increaserecovery from existing reserves.

 

On April 10, 2008, the Government of Albertaintroduced two new royalty programs to be implemented along with the NRF andintended to encourage the development of deeper, higher cost oil and gas reserves.  A five-year program for conventional oilexploration wells over 2,000 metres provides qualifying wells with up to a $1million or 12 months of royalty relief, whichever comes first, and a five-yearprogram for natural gas wells deeper than 2,500 metres provides a sliding scaleroyalty credit based on depth of up to$3,750 per metre.

 

On November 19, 2008, in response to the dropin commodity prices experienced during the second half of 2008, the Governmentof Alberta announced the introduction of a five-year program of transitionalroyalty rates with the intent of promoting new drilling.  The five-year transition option is designedto provide lower royalties at certain price levels in the initial years of awell’s life when production rates are expected to be the highest.  Under this new program companies drilling newnatural gas or conventional oil deep wells (between 1,000 and 3,500 m) aregiven a one-time option, on a well-by-well basis, to adopt either the newtransitional royalty rates or those outlined in the NRF.  Pursuant to the changes made to Alberta’sroyalty structure announced on March 11, 2010, producers will only be ableto elect to adopt the transitional royalty rates prior to January 1, 2011and producers that have already elected to adopt the transitional royalty ratesas of that date will be permitted to switch to Alberta’s conventional royaltystructure.  On December 31, 2013,all producers operating under the transitional royalty rates will automaticallybecome subject to Alberta’s conventional royalty structure.

 

On March 3, 2009, the Government of Albertaannounced a three-point incentive program in order to stimulate new andcontinued economic activity in Alberta. The program introduced a drilling royalty credit for new conventionaloil and natural gas wells and a new well royalty incentive program, bothapplying to conventional oil or natural gas wells drilled between April 1,2009 and March 31, 2010.  Thedrilling royalty credit provides up to a $200 per metre royalty credit for newwells and is primarily expected to benefit smaller producers since the maximumcredit available will be determined using the company’s production level in2008 and its drilling activity between April 1, 2009 and March 31,2010, favouring smaller producers with lower activity levels.  The new well incentive program initiallyapplied wells that began producing conventional oil or natural gas between April 1,2009 and March 31, 2010 and provided for a maximum five per cent royaltyrate for the first 12 months of production on a maximum of 50,000 barrels ofoil or 500 MMcf of natural gas.  In June,2009, the Government of Alberta announced the extension of these two incentiveprograms for one year to March 31, 2011. On March 11, 2011, the Government of Alberta announced that theincentive program rate of five per cent for the first 12 months of productionwould be made permanent, with the same volume limitations.

 

In addition to the foregoing, Alberta currentlymaintains a royalty reduction program for low productivity oil and oil sandswells, a royalty adjustment program for deep marginal gas wells and a royaltyexemption for re-entry wells, among others.

 

***British Columbia***

*** ***

Producers of oil and natural gas from Crown lands inBritish Columbia are required to pay annual rental payments, currently at arate of $3.50 per hectare, and make monthly royalty payments in respect of oiland natural gas produced.  The amountpayable as a royalty in respect of oil depends on the type and vintage of theoil, the quantity of oil produced in a month and the value of that oil.  Generally, oil is classified as either lightor heavy and the vintage of oil is based on the determination of whether theoil is produced from a pool discovered before October 31, 1975 (“oldoil”), between October 31, 1975 and June 1, 1998 (“new oil”), orafter June 1, 1998 (“third-tier oil”). The royalty calculation takes into account the production of oil on awell-by-well basis, the specified royalty rate for a given vintage of oil, theaverage unit selling price of the oil and any applicable royaltyexemptions.  Royalty rates are reduced onlow productivity wells, reflecting the higher unit costs of extraction, and arethe lowest for third-tier oil, reflecting the higher unit costs of bothexploration and extraction.

 

The royalty payable in respect of natural gasproduced on Crown lands is determined by a sliding scale formula based on areference price, which is the greater of the average net price obtained by theproducer and a prescribed minimum price. For non-conservation gas (not produced in association with oil), theroyalty rate depends on the date of acquisition of the oil and natural gastenure rights and the spud date of the well and may also be impacted by theselect price, a parameter used in the royalty rate formula to account forinflation.  Royalty rates are fixed for 

 

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certain classes of non-conservation gas when thereference price is below the select price. Conservation gas is subject to a lower royalty rate thannon-conservation gas as an incentive for the production and marketing ofnatural gas which might otherwise have been flared.

 

Producers of oil and natural gas from freehold landsin British Columbia are required to pay monthly freehold production taxes.  For oil, the level of the freehold productiontax is based on the volume of monthly production.  For natural gas, the freehold production taxis determined using a sliding scale formula based on the reference pricesimilar to that applied to natural gas production on Crown land, and depends onwhether the natural gas is conservation gas or non-conservation gas.

 

As at the beginning of 2009, British Columbiamaintained a number of targeted royalty programs for key resource areasintended to increase the competitiveness of British Columbia’s low productivitywells.  These include both royalty creditand royalty reduction programs, including the following:

 

·      *Summer Royalty Credit Program* providing aroyalty credit of 10 per cent of drilling and completion costs up to $100,000for wells drilled between April 1 and November 30 of each year,intended to increase summer drilling activity, employment and businessopportunities in northeastern British Columbia;

 

·      *Deep Royalty Credit Program* providing aroyalty credit equal to approximately 23 per cent of drilling and completioncosts for vertical wells with a  truevertical depth greater than 2,500 metres and horizontal wells with a  true vertical depth greater than 2,300 metresspud between December 1, 2003 and September 1, 2009;

 

·      *Deep Re-Entry Royalty Credit Program*providing royalty credits for deep re-entry wells with a true vertical depthgreater than 2,300 metres and a re-entry date subsequent to December 1,2003;

 

·      *Deep Discovery Royalty Credit Program*providingthe lesser of a 3-year royalty holiday or 283,000,000 m(3) ofroyalty free gas for deep discovery wells with a  true vertical depth greater than 4,000 metreswhose surface locations are at least 20 kilometres away from the surfacelocation of any well drilled into a recognized pool within the same formation;

 

·      *Coalbed Gas Royalty Reduction and Credit Program*providinga royalty reduction for coalbed gas wells with average daily production lessthan 17,000 m(3) aswell as a royalty credit for coalbed gas wells equal to $50,000 for wellsdrilled on Crown land and a tax credit equal to $30,000 for wells drilled onfreehold land;

 

·      *Marginal Royalty Reduction Program*providing royalty breaks for low productivity natural gas wells with averagemonthly production under 25,000 m(3) during the first 12production months and average daily production less than 23 m(3) forevery metre of marginal well depth;

 

·      *Ultra-Marginal Royalty Reduction Program*providing additional royalty breaks for low productivity shallow natural gaswells with a true vertical depth of less than 2,300 metres, average monthlyproduction under 60,000 m(3) during the first 12production months and average daily production less than 11.5 m(3) (developmentwells) or 17 m(3) (exploratory wildcat wells) for every 100metres of marginal well depth;

 

·      *Net Profit Royalty Reduction Program* providing reduced initial royalty rates tofacilitate the development and commercialization of technically complexresources such as coalbed gas, tight gas, shale gas and enhanced-recoveryprojects, with higher royalty rates applied once capital costs have beenrecovered.

 

Oil produced from an oil well event on either Crownor freehold land and completed in a new pool discovery subsequent to June 30,1974 may also be exempt from the payment of a royalty for the first 36 monthsof production or 11,450 m(3) of production, whichever comes first.

 

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On March 2, 2009, the Government of BritishColumbia announced the 2009 Infrastructure Royalty Credit Program (the “**Infrastructure Royalty Credit Program**”)which allocates $120 million in royalty credits for oil and gas companies.  The Infrastructure Royalty Credit Programprovides royalty credits for up to 50 per cent of the cost of certain approvedroad construction or pipeline infrastructure projects intended to improve, ormake possible, the access to new and underdeveloped oil and gas areas.  The Government of British Columbia hasrecently announced the same level of funding for the 2010 InfrastructureRoyalty Credit Program.

 

On August 6, 2009, the Government of BritishColumbia announced an oil and gas stimulus package designed to attractinvestment in and create economic benefits for British Columbia.  The stimulus package includes four royalty initiativesrelated primarily to natural gas drilling and infrastructure development.  Natural gas wells spudded within the 10-monthperiod from September 1, 2009 to June 30, 2010 and brought onproduction by December 31, 2010 qualify for a two per cent royalty ratefor the first 12 months of production, beginning from the first month ofproduction for the well (the “**Royalty ReliefProgram**”).  British Columbia’sexisting Deep Royalty Credit Program was permanently amended for wells spuddedafter August 31, 2009 by increasing the royalty deduction on deep drillingfor natural gas by 15 per cent and extending the program to include horizontalwells drilled to depths of between 1,900 and 2,300 metres.  Wells spud between September 1, 2009 andJune 30, 2010 may qualify for both the Royalty Relief Program and the DeepRoyalty Credit Program but will only receive the benefits of one program at atime.  An additional $50 million was alsoallocated to be distributed through the Infrastructure Royalty Credit Programto stimulate investment in oilfield-related road and pipeline construction.

 

***Saskatchewan***

*** ***

In Saskatchewan, the amount payable as a royalty inrespect of oil depends on the type and vintage of oil, the quantity of oilproduced in a month, the value of the oil produced and specified adjustmentfactors determined monthly by the provincial government.  For Crown royalty and freehold production taxpurposes, conventional oil is classified as “heavy oil”, “southwest designatedoil” or “non-heavy oil other than southwest designated oil”.  The conventional royalty and production taxclassifications (“fourth tier oil”, “third tier oil”, “new oil” and “old oil”)depend on the finished drilling date of a well and are applied to each of thethree crude oil types slightly differently. Heavy oil is classified as third tier oil (having a finished drillingdate on or after January 1, 1994 and before October 1, 2004), fourthtier oil (having a finished drilling date on or after October 1, 2002) ornew oil (not classified as either third tier oil or fourth tier oil).  Southwest designated oil uses the samedefinitions of third and fourth tier oil but new oil is defined as conventionaloil produced from a horizontal well having a finished drilling date on or afterFebruary 9, 1998 and before October 1, 2002.  For non-heavy oil other than southwestdesignated oil, the same classification is used but new oil is defined asconventional oil produced from a vertical well completed after 1973 and havinga finished drilling date prior to 1994, whereas old oil is defined asconventional oil not classified as third or fourth tier oil or new oil.

 

Base prices are used to establish lower limits inthe price-sensitive royalty structure for conventional oil.  Where average wellhead prices are below theestablished base prices of $100 per m(3) for thirdand fourth tier oil and $50 per m(3) for new oil and oldoil, base royalty rates are applied. Base royalty rates are 5 per cent for all fourth tier oil, 10 per centfor heavy oil that is third tier oil or new oil, 12.5 per cent for southwestdesignated oil that is third tier oil or new oil, 15 per cent for non-heavy oilother than southwest designated oil that is third tier or new oil, and 20 percent for old oil.  Where average wellheadprices are above base prices, marginal royalty rates are applied to theproportion of production that is above the base oil price.  Marginal royalty rates are 30 per cent forall fourth tier oil, 25 per cent for heavy oil that is third tier oil or new oil,35 per cent for southwest designated oil that is third tier oil or new oil, 35per cent for non-heavy oil other than southwest designated oil that is thirdtier or new oil, and 45 per cent for old oil.

 

The amount payable as a royalty in respect ofnatural gas production is determined by a sliding scale based on a referenceprice (which is the greater of the amount obtained by the producer and aprescribed minimum price), the quantity produced in a given month, the type ofnatural gas, and the vintage of the natural gas.  Like conventional oil, natural gas isclassified as “non-associated gas” or “associated gas” and royalty rates aredetermined according to the finished drilling date of the respective well.  As an incentive for the production and marketingof natural gas which may have been flared, the royalty rate on natural gasproduced in association with oil is less than on non-associated naturalgas.  Non-associated gas is classified asnew gas (having a finished drilling date before February 9, 1998 with afirst production date on or after October 1, 1976), third tier gas (havinga finished drilling date on or after February 9, 1998 and before October 1,2002), fourth tier gas (having a finished drilling date on or after October 1,2002) and old gas (not classified as either third tier, fourth tier or newgas).  A similar classification 

 

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is used for associated gas except that theclassification of old gas is not used, the definition of fourth tier gas alsoincludes production from oil wells with a finished drilling date prior to October 1,2002, where the individual oil well has a gas-oil production ratio in any monthof more than 3,500 m(3) of gas for every m(3) ofoil, and new gas is defined as oil produced from a well with a finished drillingdate before February 9, 1998 that received special approval, prior to October 1,2002, to produce oil and gas concurrently without gas-oil ratio penalties.

 

As with conventional oil production, base prices areused to establish lower limits in the price-sensitive royalty structure fornatural gas.  Where average field-gateprices are below the established base prices of $50 per thousand m(3) forthird and fourth tier gas and $35 per thousand m(3) for new gasand old gas, base royalty rates are applied. Base royalty rates are five per cent for all fourth tier gas, 15 percent for third tier or new gas, and 20 per cent for old gas.  Where average well-head prices are above baseprices, marginal royalty rates are applied to the proportion of production thatis above the base gas price.  Marginalroyalty rates are 30 per cent for all fourth tier gas, 35 per cent for thirdtier and new gas, and 45 per cent for old gas**.**

 

The Government of Saskatchewan currently provide anumber of targeted incentive programs. These include both royalty reduction and incentive volume programs,including the following:

 

·      *Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilledon or after October 1, 2002*providing reducedCrown royalty and freehold tax rates on incentive volumes of 8,000 m(3) fordeep development vertical oil wells, 4,000 m(3) fornon-deep exploratory vertical oil wells and 16,000 m(3) for deepexploratory vertical oil wells (more than 1,700 metres or within certainformations);

 

·      *Royalty/Tax Incentive Volumes for Exploratory Gas WellsDrilled on or after October 1, 2002*providing reducedCrown royalty and freehold tax rates on incentive volumes of 25,000,000 m(3) forqualifying exploratory gas wells;

 

·      *Royalty/Tax Incentive Volumes for Horizontal Oil WellsDrilled on or after October 1, 2002*providing reducedCrown royalty and freehold tax rates on incentive volumes of 6,000 m(3) fornon-deep horizontal oil  wells and 16,000m(3) fordeep horizontal oil  wells (more than1,700 metres or within certain formations);

 

·      *Royalty/Tax Regime for Incremental Oil Produced from New orExpanded Waterflood Projects Implemented on or after October 1, 2002*treating incremental production from waterflood projects as fourth tier oil forthe purposes of royalty calculation;

 

·      *Royalty/Tax Regime for Enhanced Oil Recovery Projects(Excluding Waterflood Projects) Commencing prior to April 1, 2005*providing Crown royalty and freehold tax determinations based in part on theprofitability of enhanced recovery projects pre- and post-payout; and

 

·      *Royalty/Tax Regime for Enhanced Oil Recovery Projects(Excluding Waterflood Projects) Commencing on or after April 1, 2005*providing a Crown royalty of 1 per cent of gross revenues on enhanced oilrecovery projects pre-payout and 20 per cent post-payout and a freeholdproduction tax of 0 per cent on operating income from enhanced oil recoveryprojects pre-payout and 8 per cent post-payout.

 

In 1975, the Government ofSaskatchewan introduced a Royalty Tax Rebate (“**RTR**”) as a response to the Government of Canada disallowingcrown royalties and similar taxes as a deductible business expensefor income tax purposes.  As of January 1,2007, theremaining balance of any unused RTR will be limited in its carry forwardto seven years since the Government of Canada’s initiativeto reintroduce the full deduction of provincial resource royalties from federaland provincial taxable income. Saskatchewan’s RTR will be wound down as a result of the Government ifCanada’s plan to reintroduce full deductibility of provincial resourceroyalties for corporate income tax purposes.

 

**LandTenure**

** **

Crude oil and natural gas located in the westernprovinces is owned predominantly by the respective provincial governments.  Provincial governments grant rights toexplore for and produce oil and natural gas pursuant to leases, 

 

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licences, and permits for varying terms from twoyears, and on conditions set forth in provincial legislation includingrequirements to perform specific work or make payments.  Oil and natural gas located in such provincescan also be privately owned and rights to explore for and produce such oil andnatural gas are granted by lease on such terms and conditions as may be negotiated.

 

Each of the provinces of Alberta, British Columbiaand Saskatchewan has implemented legislation providing for the reversion to theCrown of mineral rights to deep, non-productive geological formations at theconclusion of the primary term of a lease or license.

 

In Alberta, the NRF includes a policy of “shallowrights reversion” which provides, for the first time in western Canada, for thereversion to the Crown of mineral rights to shallow, non-productive geologicalformations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009,shallow rights reversion will be applied at the conclusion of the primary termof the lease or license.  Holders ofleases or licences that have been continued indefinitely prior to January 1,2009 will receive a notice regarding the reversion of the shallow rights, whichwill be implemented three years from the date of the notice.  The order in which these agreements willreceive the reversion notice will depend on their vintage and location, withthe older leases and licenses receiving reversion notices first beginning in January 2011.  Leases and licences that were granted priorto January 1, 2009 but continued after that date will not be subject toshallow rights reversion until they reach the end of their primary term and arecontinued (at which time deep rights reversion will be applied); thereafter,the holders of such agreements will be served with shallow rights reversionnotices based on vintage and location similar to leases and licences that werealready continued as of January 1, 2009.

 

**EnvironmentalRegulation**

** **

The oil and natural gas industry is currentlysubject to environmental regulations pursuant to a variety of provincial andfederal legislation.  Such legislationprovides for restrictions and prohibitions on the release or emission ofvarious substances produced in association with certain oil and gas industryoperations, such as sulphur dioxide and nitrous oxide.  In addition, such legislation requires thatwell and facility sites be abandoned and reclaimed to the satisfaction ofprovincial authorities.  Compliance withsuch legislation can require significant expenditures and a breach of suchrequirements may result in suspension or revocation of necessary licenses andauthorizations, civil liability for pollution damage, and the imposition ofmaterial fines and penalties.

 

In December, 2008, the Government of Albertareleased a new land use policy for surface land in Alberta, the Alberta LandUse Framework (the “**ALUF**”).  The ALUF sets out an approach to managepublic and private land use and natural resource development in a manner thatis consistent with the long-term economic, environmental and social goals ofthe province.  It calls for thedevelopment of region-specific land use plans in order to manage the combinedimpacts of existing and future land use within a specific region and theincorporation of a cumulative effects management approach into such plans.  The *AlbertaLand Stewardship Act* (the “**ALSA**”)was proclaimed in force in Alberta on October 1, 2009, providing thelegislative authority for the Government of Alberta to implement the policiescontained in the ALUF.  Regional plansestablished pursuant to the ALSA are deemed to be legislative instruments equivalentto regulations and are binding on the Government of Alberta and provincialregulators, including those governing the oil and gas industry.  In the event of a conflict or inconsistencybetween a regional plan and another regulation, regulatory instrument orstatutory consent, the regional plan will prevail.  Further, the ALSA requires local governments,provincial departments, agencies and administrative bodies or tribunals toreview their regulatory instruments and make any appropriate changes to ensurethat they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previouslyissued statutory consents such as regulatory permits, licenses, approvals andauthorizations in order for the purpose of achieving or maintaining anobjective or policy resulting from the implementation of a regional plan.  Among the measures to support the goals ofthe regional plans contained in the ALSA are conservation easements, which canbe granted for the protection, conservation and enhancement of land; and conservationdirectives, which are explicit declarations contained in a regional plan to setaside specified lands in order to protect, conserve, manage and enhance theenvironment.  Although no regional planshave been established under the ALSA, the planning process is underway for theLower Athabasca Region (which contains the majority of oil sands development)and the South Saskatchewan Region.  Whilethe potential impact of the regional plans established under the ALSA cannotyet be determined, it is clear that such regional plans may have a significantimpact on land use in Alberta and may affect the oil and gas industry.

 

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**ClimateChange Regulation**

** **

***Federal***

 

In December 2002, the Government of Canadaratified the Kyoto Protocol (“**Kyoto Protocol**”),which requires a reduction in greenhouse gas emissions by signatory countriesbetween 2008 and 2012.  The KyotoProtocol officially came into force on February 16, 2005 and commitsCanada to reduce its greenhouse gas emissions levels to 6 per cent below 1990“business-as-usual” levels by 2012.

 

In anticipationof the expiry of the Kyoto Protocol in 2012, government leaders andrepresentatives from approximately 170 countries met in Copenhagen, Denmarkfrom December 6 to 18, 2009 (the “**Copenhagen Conference**”)to attempt to negotiate a successor to the Kyoto Protocol.  The primary result of the CopenhagenConference was the Copenhagen Accord, which represents a broad politicalconsensus rather than a binding international treaty like the Kyoto Protocoland has not been endorsed by all participating countries.  The Copenhagen Accord reinforces thecommitment to reducing GHG emissions contained in the Kyoto Protocol andpromises funding to help developing countries mitigate and adapt to climatechange.  Although certain countries,including Canada, have committed to reducing their emissions individually orjointly by at least 80 per cent by 2050, the Copenhagen Accord does not establishbinding GHG emissions reduction targets. The Copenhagen Accord calls for a review and implementation of itsstated goals by 2016.

 

In response tothe Copenhagen Accord, the Government of Canada has recently indicated that itwill seek to achieve a 17 per cent reduction in greenhouse gas emissions from2005 levels by 2020.  This goal issimilar to the goal expressed in previous policy documents which are discussedbelow.

 

On February 14, 2007, the House of Commonspassed Bill C-288, *An Act to ensure Canadameets its global climate change obligations under the Kyoto Protocol*.  The resulting *KyotoProtocol Implementation Act* came into force on June 22,2007.  Its stated purpose is to “ensurethat Canada takes effective and timely action to meet its obligations under theKyoto Protocol and help address the problem of global climate change.” Itrequires the federal Minister of the Environment to, among other things,produce an annual climate change plan detailing the measures to be taken toensure Canada meets its obligations under the Kyoto Protocol.  It also authorizes the establishment ofregulations respecting matters such as emissions limits, monitoring, tradingand enforcement.

 

On April 26, 2007, the Government of Canadareleased “Turning the Corner: An Action Plan to Reduce Greenhouse Gases and AirPollution” (the “**Action Plan**”) which set forth aplan for regulations to address both greenhouse gases and air pollution.  An update to the Action Plan, “Turning theCorner: Regulatory Framework for Industrial Greenhouse Gas Emissions” was releasedon March 10, 2008 (the “**Updated Action Plan**”).  Althoughdraft regulations for the implementation of the Updated Action Plan wereintended to be published in the fall of 2008 and become binding on January 1,2010, no such regulations have been proposed to date.  Further, representatives the Government ofCanada have recently indicated that the proposals contained in the UpdatedAction Plan will be modified to ensure consistency with the directionultimately taken by the United States with respect to greenhouse gas emissionsregulation.  The approach of the UnitesStates is expected to include an absolute cap on emissions combined withallowances to be used for compliance that may be partially auctioned off toregulated entities.  It is also unclearwhether the approach adopted by the United States will provide for the paymentinto a technology fund as a compliance mechanism, as is currently permitted inAlberta and by the Updated Action Plan. As a result, many provisions of the Updated Action Plan, describedbelow, are expected to be significantly modified.

 

The stated goal of the Updated Action Plan, ascurrently drafted, is to reduce greenhouse gas emissions to 20 per cent below2006 levels by 2020 and 60-70 per cent by 2050. As noted above, the goal has now been modified by the Government ofCanada.  The Updated Action Plan outlinesemissions intensity-based targets which will be applied to regulated sectors oneither a facility-specific, sector-wide or company-by-company basis.  Facility-specific targets applied to theupstream oil and gas, oil sands, petroleum refining and natural gas pipelinessectors.  Unless a minimum regulatorythreshold applies, all facilities within a regulated sector will be subject tothe emissions intensity targets.

 

The Updated Action Plan makes a distinction between“Existing Facilities” and “New Facilities”. For Existing Facilities, the Updated Action Plan requires an emissionsintensity reduction of 18 per cent below 2006 levels by 2010 followed by acontinuous annual emissions intensity improvement of 2 per cent.  “New Facilities” are defined as facilitiesbeginning operations in 2004 and include both greenfield facilities and majorfacility expansions that (i) 

 

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result in a 25 per cent or greater increase in afacility’s physical capacity, or (ii) involve significant changes to theprocesses of the facility.  NewFacilities will be given a 3-year grace period during which no emissionsintensity reductions will be required. Targets requiring an annual two per cent emissions intensity reductionwill begin to apply in the fourth year of commercial operation of a NewFacility.  Further, emissions intensitytargets for New Facilities will be based on a cleaner fuel standard to encouragecontinuous emissions intensity reductions over time.  The method of applying this cleaner fuelstandard has not yet been determined.  Inaddition, the Updated Action Plan indicates that targets for the adoption ofcarbon capture and storage (“**CCS**”)technologies will be developed for oil sands in-situ facilities, upgraders andcoal-fired power generators that begin operations in 2012 or later.  These targets will become operational in2018, although the exact nature of the targets has not yet been determined.

 

Given the large number of small facilities withinthe upstream oil and gas and natural gas pipeline sectors, facilities withinthese sectors will only be subject to emissions intensity targets if they meetcertain minimum emissions thresholds. That threshold will be (i) 50,000 tonnes of CO2 equivalents per facility per year for naturalgas pipelines; (ii) 3,000 tonnes of CO2 equivalents per facility per year for theupstream oil and gas facility; and (iii) 10,000 boe/d/company.  These regulatory thresholds are significantlylower than the regulatory threshold in force in Alberta, discussed below.  In all other sectors govern by the Updated ActionPlan, all facilities will be subject to regulation

 

Four separate compliance mechanisms are provided forin the Updated Action Plan in respect of the above targets: Technology Fundcontributions, offset credits, clean development credits and credits for earlyaction.  Regulated entities will be ableto use Technology Fund contributions to meet their emissions intensitytargets.  The contribution rate forTechnology Fund contributions will increase over time, beginning at $15 pertonne of CO2 equivalent for the 2010-12 period, rising to$20 in 2013, and thereafter increasing at the nominal rate of GDP growth.  Maximum contribution limits will also declinefrom 70 per cent in 2010 to 0 per cent in 2018. Monies raised through contributions to the Technology Fund will be usedto invest in technology to reduce greenhouse gas emissions.  Alternatively, regulated entities may be ableto receive credits for investing in large-scale and transformative projects atthe same contribution rate and under similar requirements as described above.

 

The offset system is intended to encourage emissionsreductions from activities outside of the regulated sphere, allowingnon-regulated entities to participate in and benefit from emissions reductionactivities.  In order to generate offsetcredits, project proponents must propose and receive approval for emissionsreduction activities that will be verified before offset credits will be issuedto the project proponent.  Those creditscan then be sold to regulated entities for use in compliance or non-regulatedpurchasers that wish to either purchase the offset credits for cancellation orbanking for future use or sale.

 

Under the Updated Action Plan, regulated entitieswill also be able to purchase credits created through the Clean DevelopmentMechanism of the Kyoto Protocol which facilitates investment by developednations in emissions-reduction projects in developing countries.  The purchase of such Emissions ReductionCredits will be restricted to 10 per cent of each firm’s regulatory obligation,with the added restriction that credits generated through forest sink projectswill not be available for use in complying with the Canadian regulations.

 

Finally, a one-time credit of up to 15 milliontonnes worth of emissions credits will be awarded to regulated entities foremissions reduction activities undertaken between 1992 and 2006.  These credits will be both tradable andbankable.

 

***Alberta***

 

Alberta enacted the *ClimateChange and Emissions Management Act*(the “**CCEMA**”) on July 1, 2007, amending it through the *Climate Change and Emissions Management Amendment Act*which received royal asseton November 4, 2008.  The CCEMA isbased on an emissions intensity approach similar to the Updated Action Plan andaims for a 50 per cent reduction from 1990 emissions relative to GDP by 2020.

 

Alberta facilities emitting more than 100,000 tonnesof greenhouse gases a year are subject to comply with the CCEMA.  Similarly to the Updated Action Plan, theCCEMA and the associated *Specified Gas EmittersRegulation* make a distinction between “Existing Facilities” and “NewFacilities”.  Existing Facilities are defined as facilities that completed theirfirst year of commercial operation prior to January 1, 2008 or that havecompleted 8 or more years of commercial operation.  Existing Facilities were required to reduce their emissionsintensity by March 31, 2008 by 12 per cent from a baseline established bytheir average emissions intensity between 2003 and 2005.  New 

 

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Facilities are defined asfacilities that completed their first year of commercial operation subsequentto December 31, 2008, have completed less than 8 years of commercialoperation, or are designated as New Facilities in accordance with the *Specified Gas Emitters Regulation*.  New Facilities are alsorequired to reduce their emissions intensity by 12 per cent but this target isbased on the emissions intensity of the facility in its third year ofcommercial operation and does not apply during the first 3 years of operationof the New Facility.  Unlike the UpdatedAction Plan, the CCEMA does not contain any provision for continuous annualimprovements beyond the 12 per cent emissions intensity required.

 

The CCEMA contains similar compliancemechanisms as the Updated Action Plan. Regulated emitters can meet their emissions intensity targets bycontributing to the Climate Change and Emissions Management Fund (the “**Fund**”) at a rate of $15 per tonne of CO2 equivalent.  Unlike the Updated Action Plan, CCEMA containsno provisions for an increase to this contribution rate.  Emissions credits can be purchased fromregulated emitters that have reduced their emissions below the 100,000 tonnethreshold or non-regulated emitters that have generated emissions offsets throughactivities that result in emissions reductions in accordance with establishedprotocols published by the Government of Alberta.  Unlike the Updated Action Plan, the CCEMAdoes not contemplate a linkage to external compliance mechanisms such as the KyotoProtocol’s Clean Development Mechanism.

 

***British Columbia***

 

In February, 2008, British Columbia announceda revenue-neutral carbon tax that took effect July 1, 2008.  The tax is consumption-based and applied atthe time of retail sale or consumption of virtually all fossil fuels purchasedor used in British Columbia.  The initiallevel of the tax was set at $10 per tonne of CO2 equivalent and rose to $15per tonne of CO2 equivalent on July 1,2009.  It is scheduled to furtherincrease at a rate of $5 per tonne of CO2 equivalent on July 1 of every year untilit reaches $30 per tonne of CO2 equivalent on July 31, 2012.  In order to make the tax revenue-neutral, British Columbia hasimplemented tax credits and reductions in order to offset the tax revenues thatthe Government of British Columbia would otherwise receive from the tax.

 

On April 3, 2008, British Columbia introduced the *Greenhouse Gas Reduction (Cap and Trade) Act* (the “**Cap and Trade Act**”) which received royal assent on May 29,2008 and will come into force by regulation of the Lieutenant Governor inCouncil.  Unlike the emissions intensityapproach taken by the federal government and the Government of Alberta, the Capand Trade Act establishes an absolute cap on greenhouse gas emissions.  It is expected that greenhouse gas emissionsrestrictions will be applied to facilities emitting more than 25,000 tonnes of CO2 equivalents per year, whichwill be required to meet established targets through a combination of emissionsallowances issued by the Government of British Columbia and the purchase ofemissions offsets generated through activities that result in a reduction ingreenhouse gas emissions.  Although morespecific details of British Columbia’s cap and trade plan have not yet beenfinalized, on January 1, 2010, new reporting regulations came into forcerequiring all British Columbia facilities emitting over 10,000 tonnes of CO2 equivalents per year to beginreporting their emissions.  Facilitiesreporting emissions greater than 25,000 tonnes of CO2 equivalentsper year are required to have their emissions report verified by a third party.

 

***Saskatchewan***

 

On May 11, 2009, the Government of Saskatchewanannounced *The Management and Reduction of Greenhouse GasesAct*(the “**MRGGA**”) toregulate greenhouse gas emissions in the province.  Although the MRGGA has only passed firstreading in the Saskatchewan legislature and the specific details of thelegislation have not yet been determined, it is expected that the MRGGA willadopt the goal of a 20 per cent reduction in greenhouse gas emissions by 2020and permit the use of technology fund contributions and emissions offsets incompliance, similar to both the federal and Alberta climate changeinitiatives.  It remains unclear whetherthe scheme implemented by the MRGGA will be based on emissions intensity or anabsolute cap on emissions.

 

**RISK FACTORS**

 

The followingis a summary of certain risk factors relating to the business of the Trust andARC Resources which prospective investors should carefully consider beforedeciding whether to purchase Trust Units or Exchangeable Shares.  Residents of the United States and othernon-residents of Canada should have additional regard to the risk factors underthe heading “Risk Factors Applicable to Residents of the United States andOther Non-Residents of Canada”.

 

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We are alimited purpose trust and are entirely dependent upon the operations and assetsof ARC Resources through our ownership, directly and indirectly, of securitiesof ARC Resources, including the common shares of ARC Resources, the Notes andthe Royalties.  Accordingly, our abilityto pay distributions to Unitholders is dependent upon the ability of ARC Resourcesto meet its interest, principal, dividend and other distribution obligations onthe securities of ARC Resources and to pay the Royalties.  ARC Resources’ income is received from theproduction of oil and natural gas from its Canadian resource properties and issusceptible to the risks and uncertainties associated with the oil and naturalgas industry generally.  If the oil andnatural gas reserves associated with ARC Resources’ resource properties are notsupplemented through additional development or the acquisition of additionaloil and natural gas properties, the ability of ARC Resources to meet itsobligations to us and our ability to pay distributions to Unitholders may beadversely affected.

 

**Risk Relating to Our Business and Operations**

 

***Declines in oil and natural gas prices will adversely affect ourfinancial condition***

 

Ouroperational results and financial condition, and therefore the amounts we payto Unitholders as distributions, will be dependent on the prices received foroil and natural gas production. Oil and natural gas prices have exhibitedextreme volatility over the past few years and monthly distributions thatreached a high point of $0.28 per Trust Unit in August of 2008 declined to$0.10 per Trust Unit at December 31, 2009. Declines in oil and natural gas prices will result in further declinesin, or elimination of, such distributions. Oil and natural gas prices are determined by economic factors and in thecase of oil prices, political factors and a variety of additional factors beyondour control.  These factors include economicconditions, in the United States, Canada and worldwide, the actions of theOrganization of Petroleum Exporting Countries, governmental regulation,political stability in the Middle East and elsewhere, internal capacity toproduce natural gas in the United States from shale deposits, the foreignsupply of oil and natural gas, risks of supply disruption, the price of foreignimports and the availability of alternative fuel sources.  Any substantial and extended decline in theprice of oil and natural gas would have an adverse effect on the carrying valueof our proved and probable reserves, net asset value, borrowing capacity,revenues, profitability and cash flows from operating activities and ultimatelyon our financial condition and therefore on the amounts to be distributed toour Unitholders.

 

***Increases in interest rates or the value of the Canadian dollar againstthe U.S. dollar will adversely affect our financial condition***

 

There is arisk that interest rates will increase given the current historical low levelof interest rates.  An increase ininterest rates could result in a significant increase in the amount we pay toservice debt, resulting in a decrease in distributions to Unitholders, andcould impact the market price of the Trust Units.

 

World oilprices are quoted in United States dollars and the price received by Canadianproducers is therefore affected by the Canadian/U.S. dollar exchange rate thatmay fluctuate over time and in fact increased in 2009 by eight per cent.  A material increase in the value of theCanadian dollar negatively impacts our production revenue and our ability tomaintain future distributions.

 

***The global economy has not fully recovered and unforeseen events maynegatively impact our financial condition***

 

Market eventsand conditions, including disruptions in the international credit markets andother financial systems and the deterioration of global economic conditions,caused significant volatility to commodity prices over the last few years.  These conditions worsened in 2008 and early2009, causing a loss of confidence in the broader U.S. and global credit andfinancial markets and resulting in the collapse of, and government interventionin, major banks, financial institutions and insurers and creating a climate ofgreater volatility, less liquidity, widening of credit spreads, a lack of pricetransparency, increased credit losses and tighter credit conditions.  Notwithstanding various actions bygovernments, concerns about the general condition of the capital markets,financial instruments, banks, investment banks, insurers and other financialinstitutions caused the broader credit markets to further deteriorate and stockmarkets to decline substantially. Although economic conditions improved towards the latter portion of 2009and continue to improve in early 2010, these factors have negatively impactedcompany and trust valuations and continue to impact the performance of theglobal economy going forward.

 

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***Our bank credit facility will need to be renewed prior to April 11,2011 and failure to renew, in whole or in part, or at higher interest chargeswill adversely affect our financial condition***

 

We currentlyhave an $800 million syndicated credit facility with eleven banks of which wehad drawn $497.3 million as at December 31, 2009.  In the event that the facility is notextended before April 11, 2011, indebtedness under the facility will berepayable at that date.  There is also arisk that the credit facility will not be renewed for the same amount or on thesame terms.

 

We had U.S.$298.1 million of U.S. denominated and Cdn $29 million of long-term debtoutstanding as at December 31, 2009, which requires principal repaymentsstarting in April 2010 and continuing until April 2021.  We intend to fund these debt maturities withexisting credit facilities.

 

The Trust isrequired to comply with covenants under the credit facility and under our U.S.denominated long-term notes.  In theevent that we do not comply with covenants under the credit facility and ourlong term notes, our access to capital could be restricted or repayment couldbe required on an accelerated basis by our lenders, and the ability to makedistributions to our Unitholders may be restricted.  The lenders have security over substantiallyall of our assets.  If we become unableto pay our debt service charges or otherwise commit an event of default such asbreach of our financial covenants, the lender may foreclose on or sell ourworking interests in our properties.

 

Amounts paidin respect of interest and principal on debt may reduce distributions.  Variations in interest rates and scheduledprincipal repayments could result in significant changes in the amount requiredto be applied to debt service before payment of the Royalties and interest onthe Long Term Notes and distributable income. Certain covenants of the agreements with our lenders may also limitdistributions.  Although we believe thecredit facilities will be sufficient for our immediate requirements, there canbe no assurance that the amount will be adequate for our future financialobligations including our future capital expenditure programs, or thatadditional funds will be able to be obtained.

 

For moreinformation, see “Other Information Relating to Our Business — Borrowing”.

 

***We have been historically reliant on external sources of capital,borrowings and equity sales, and if unavailable, our financial condition willbe adversely affected***

 

As futurecapital expenditures will be financed out of cash generated from operatingactivities, borrowings and possible future equity sales, our ability to do sois dependent on, among other factors, the overall state of capital markets andinvestor appetite for investments in the energy industry and our securities inparticular.

 

To the extentthat external sources of capital become limited or unavailable or available ononerous terms, our ability to make capital investments and maintain or expandexisting assets and reserves may be impaired, and our assets, liabilities,business, financial condition, results of operations and distributions may bematerially and adversely affected as a result.

 

Alternatively,we may issue additional Trust Units from treasury at prices which may result ina decline in production per Trust Unit and reserves per Trust Unit or we maywish to borrow to finance significant acquisitions or development projects toaccomplish our long term objectives on less than optimal terms or in excess ofour optimal capital structure.

 

***Ourhedging activities may negatively impact our income and the financial conditionof the Corporation.***

 

We may managethe risk associated with changes in commodity prices by entering into oil ornatural gas price hedges.  If we hedgeour commodity price exposure, we may forego some of the benefits we wouldotherwise experience if commodity prices were to increase.  For more information in relation to ourcommodity hedging program, see “Statement of Reserve Data and Other Oil and GasInformation — Other Oil and Gas Information — Forward Contracts”.  We may initiate certain hedges to attempt tomitigate the risk of the Canadian dollar appreciating against the U.S.dollar.  The increase in the exchangerate for the Canadian dollar and future Canadian/United States exchange rateswill impact future distributions and the future value of our reserves asdetermined by independent evaluators. These hedging activities could expose us to losses and to credit riskassociated with counterparties with which we contract.

 

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***Failure of third parties to meet their contractualobligations to us may have a material adverse affect on our financial condition***

 

We are exposedto third party credit risk through our contractual arrangements with ourcurrent or future joint venture partners, third party operators, marketers ofour petroleum and natural gas production and other parties.  Poor credit conditions in the industry and ofjoint venture partners may impact a joint venture partner’s willingness toparticipate in our ongoing capital program, potentially delaying the programand the results of such program until we find a suitable alternative partner.

 

***Our ability to maintain distributions is dependent on a number offactors including volatility of prices for oil and gas, interest rates, sourcesof capital, changes in legislation and those set forth below***

 

Our ability toadd to our oil and natural gas reserves is highly dependent on our success inexploiting existing properties and acquiring additional reserves.  We currently distribute a significantproportion of our cash flow from operating activities to Unitholders ratherthan reinvesting it in reserves additions. Our ability to make the necessary capital investments to maintain orexpand our oil and natural gas reserves is dependent on external sources ofcapital and maintenance of our cash flow from operating activities.  To the extent that we use cash flow fromoperating activities to finance capital expenditures or property acquisitions,the level of cash flow from operating activities available for distribution toUnitholders will be reduced.  There is noassurance we will be successful in developing additional reserves or acquiringadditional reserves on terms that meet our investment objectives.  Without these reserves additions, ourreserves will deplete and as a consequence, either production from, or theaverage reserves life of, our properties will decline, which will result in areduction in the value of Trust Units and in a reduction in cash flow fromoperating activities available for distributions to Unitholders.

 

***Our business is heavily regulated and such regulationincreases our costs and may adversely affect our financial condition***

 

Oil andnatural gas operations (including land tenure, exploration, development,production, refining, transportation and marketing) are subject to extensivecontrols and regulations imposed by various levels of government, which may beamended from time to time.  Governmentsmay regulate or intervene with respect to price, taxes, royalties and theexportation of oil and natural gas. Regulation increases our costs. In order to conduct oil and gas operations, we require licenses fromvarious governmental authorities.  Therecan be no assurance that we will be able to obtain all of the licenses andpermits that may be required to conduct operations that we may wish toundertake.  See “Industry Conditions”.

 

***Income tax laws, or other laws or government incentive programs orregulations relating to our industry may in the future be changed orinterpreted in a manner that adversely affects us and our Unitholders***

 

We intend tocontinue to qualify as a mutual fund trust for purposes of the *Tax Act*. We may not, however, always be able to satisfy any future requirementsfor the maintenance of mutual fund trust status.  Should our status as a mutual fund trust belost or successfully challenged by a relevant tax authority, certain adverseconsequences may arise for us and Unitholders. Some of the significant consequences of losing mutual fund trust statusare as follows:

 

·              We would be taxed oncertain types of income distributed to Unitholders, including income generatedby the Royalties held by us.  Payment ofthis tax may have adverse consequences for some Unitholders, particularly Unitholdersthat are not residents of Canada and residents of Canada that are otherwiseexempt from Canadian income tax.

 

·              We would cease to beeligible for the capital gains refund mechanism available under Canadian taxlaws if we cease to be a mutual fund trust.

 

·              Trust Units held byUnitholders that are not residents of Canada would become taxable Canadianproperty.  These non-resident holderswould be subject to Canadian income tax on any gains realized on a dispositionof Trust Units held by them.

 

The oil andnatural gas industry is subject to extensive controls and regulations governingits operations (including land tenure, exploration, development, production,refining, transportation, and marketing) imposed by legislation

 

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enacted byvarious levels of government and with respect to pricing and taxation of oiland natural gas by agreements among the governments of Canada, Alberta, BritishColumbia, and Saskatchewan, all of which should be carefully considered byinvestors in the oil and gas industry. All of such controls, regulations and legislation are subject torevocation, amendment or administrative change, some of which have historicallybeen material and in some cases materially adverse and there can be noassurance that there will not be further revocation, amendment oradministrative change which will be materially adverse to our assets, reserves,financial condition or results of operations or prospects and our ability tomaintain distributions.

 

Taxauthorities having jurisdiction over us or Unitholders may disagree with how wecalculate our income for tax purposes or could change administrative practisesto our detriment or the detriment of Unitholders.

 

***There are numerous uncertainties inherent in estimating quantities ofrecoverable oil and natural gas reserves, including many factors beyond ourcontrol***

 

In general,estimates of economically recoverable oil and natural gas reserves andresources, the future net revenues and finding and development costs therefromare based upon a number of variable factors and assumptions, such as historicalproduction from the properties, production rates, ultimate reserve recovery,timing and amount of capital expenditures, marketability of oil and naturalgas, royalty rates, the assumed effects of regulation by governmental agenciesand future operating costs, all of which may vary materially from actualresults.

 

The reservesand recovery information contained in the GLJ Report is only an estimate andthe actual production and ultimate reserves from the properties may be greateror less than the estimates prepared by GLJ. The GLJ Report has been prepared using certain commodity priceassumptions which are described in the notes to the reserves tables.  If we realize lower prices for crude oil,natural gas liquids and natural gas and they are substituted for the priceassumptions utilized in those reserves reports, the present value of estimatedfuture net revenues for our reserves and net asset value would be reduced andthe reduction could be significant.  Theestimates in the GLJ Report are based in part on the timing and success ofactivities we intend to undertake in future years.  The reserves and estimated future netrevenues to be derived therefrom contained in the GLJ Report will be reduced infuture years to the extent that such activities do not achieve the productionperformance set forth in the GLJ Report.

 

Estimates ofproved undeveloped reserves are sometimes based upon volumetric calculationsand upon analogy to similar types of reserves rather than actual productionhistory.  Recovery factors and drainageareas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods aregenerally less reliable than those based on actual production history.  Subsequent evaluation of the same reservesbased upon production history and production practices will result invariations in the estimated reserves and such variations could be material.

 

***The Trust is in the process of converting to a corporate structurewhich may result in adverse consequences to our financial condition***

 

New federallegislation passed in June 2007, will apply a tax (“**SIFT tax**”) at the trust level ondistributions of certain income from trusts, such as the Trust, at rates of taxcomparable to the combined federal and provincial corporate tax and will treatsuch distributions as dividends to the Unitholders effective January 1,2011.  The SIFT tax results in adversetax consequences to the Trust and certain Unitholders (including mostparticularly Unitholders that are tax deferred or non-residents of Canada) andmay impact distributions from the Trust.

 

The SIFT taxwill substantially eliminate the competitive advantage that the Trust and otherCanadian energy trusts enjoyed relative to their corporate peers in raisingcapital in a tax-efficient manner, and will make the Trust Units lessattractive as an acquisition currency. As a result, it may become moredifficult for the Trust to compete effectively for acquisition opportunities.There can be no assurance that the Trust will be able to reorganize its legaland tax structure to substantially mitigate the expected impact of the SIFTtax.

 

No assurancecan be provided that the SIFT tax will not apply to us prior to January 1,2011, or that the legislation will not be further changed in a manner whichadversely affects us and our Unitholders.

 

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***Acquiring, developing and exploring for oil and natural gas involvesmany risks, which even a combination of experience, knowledge and carefulevaluation may not be able to overcome***

 

These risksinclude, but are not limited to, encountering unexpected formations orpressures, premature declines of reservoirs, blow-outs, equipment failures andother accidents, sour gas releases, uncontrollable flows of oil, natural gas orwell fluids, adverse weather conditions, pollution, other environmental risks,fires, spills and delays in payments between parties caused by operation oreconomic matters.  These risks willincrease as the Trust undertakes more exploratory activity.  Although we maintain insurance in accordancewith customary industry practice, we are not fully insured against all of theserisks.

 

Continuingproduction from a property, and to some extent the marketing of productiontherefrom, are largely dependent upon the ability of the operator of theproperty.  Other companies operate someof the properties in which we have an interest and as a result our returns onassets operated by others depends upon a number of factors outside ourcontrol.  To the extent the operatorfails to perform these functions properly, operating income may be reduced.

 

Lossesresulting from the occurrence of any of these risks may have a material adverseeffect on our business, financial condition, results of operations andprospects and our ability to maintain distributions.

 

***The Board of ARC Resources has discretion in the payment ofdistributions and may not choose to maintain distributions in certaincircumstances***

 

The TrustIndenture provides that all of the distributable income of the Trust at the endof any calendar month including December 31 shall be declared payable anddistributed to the Unitholders of record on the last day of each such calendarmonth.  The distribution by the Trust ofsuch distributable income is enforceable by such Unitholders of record.  However, if this amount is not determined anddeclared payable in accordance with the rules of the Toronto StockExchange, the right to receive this income will trade with the TrustUnits.  The Trust Indenture provides thatthis distributable income is allocated to Unitholders for tax purposes and tothe extent a Unitholder trades Trust Units in this period, they will beallocated such income but will have disposed of their right to receive suchdistribution.

 

In addition,the Trust Indenture provides that such distributable income may be paid inwhole or in part by cash, in Trust Units, or promissory notes payable in wholeor in part in cash or Trust Units on a specified date not more than 90 daysafter the record date to which the promissory note relates.  The Trust Indenture also provides for theconsolidation of the Trust Units in the discretion of the Board of Directors ofARC Resources to the pre-distribution number of Trust Units after any pro-ratadistribution of additional Trust Units to all Unitholders.  Accordingly, the Trust Indenture allows forthe payment of distributions in a form other than cash and Unitholders may havetaxable income and cash taxes payable.

 

***Our enhanced oil projects are not economically feasible in today’seconomic environment***

 

We believe ourownership of assets in Redwater and North Pembina Cardium Unit #1strategically positions us for participation in properties with large reservesof unrecovered original resources in place which may be amenable to secondaryrecovery techniques such as CO2 miscible or immiscible flooding.  The implementation of enhanced oil recoverytechniques on properties like Redwater or the North Pembina Cardium Unit #1 aresubject to significant risk factors, including the requirements of successfulresults from field pilot programs, long term supply agreements for CO2 and large scaleinfrastructure investments.  We have justbegun to devote resources to the study of such matters and no reserves arereflected in the GLJ Report for any of these enhanced recovery techniques forthe two subject properties.  In order forARC Resources to carry out its enhanced oil recovery program it is necessary toobtain CO2 at a cost effective rate which requires infrastructure to be put inplace to facilitate this process.  Underthe current regulatory environment, the economic parameters of the Trust’senhanced oil recovery programs would be limited.  There is no assurance as to when or if suchenhanced recovery techniques will be implemented, or if implemented, when or ifsuch enhanced recovery techniques would be successful.

 

***We are participating in larger projects and have moreconcentrated risk in certain areas of our operations***

 

We manage avariety of small and large projects in the conduct of our business.  We have undertaken large developmentprojects, including the construction of three gas processing plants, in northeastern British Columbia

 

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for thedevelopment of our natural gas reserves. Project delays may impact expected revenues from operations.  Significant project cost over-runs could makea project uneconomic.  Our ability toexecute projects and market oil and natural gas depends upon numerous factorsbeyond our control, including:

 

·              theavailability of processing capacity;

·              theavailability and proximity of pipeline capacity;

·              theavailability of storage capacity;

·              thesupply of and demand for oil and natural gas;

·              theavailability of alternative fuel sources;

·              theeffects of inclement weather;

·              theavailability of drilling and related equipment;

·              unexpectedcost increases;

·              accidentalevents;

·              changesin regulations;

·              theavailability and productivity of skilled labour; and

·              the regulation of theoil and natural gas industry by various levels of government and governmentalagencies.

 

Because ofthese factors, we could be unable to execute projects on time, on budget or atall, and may not be able to effectively market the oil and natural gas that weproduce.

 

***We only operate in western Canada and expansion outside of these areasmay increase our risk exposure***

 

Our operationsand expertise are currently focused on oil and gas production and developmentin the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside thisgeographic area.  In addition, the TrustIndenture does not limit our activities to oil and gas production anddevelopment, and we could acquire other energy related assets, such as oil andnatural gas processing plants or pipelines, or an interest in an oil sandsproject.  Expansion of our activitiesinto new areas may present new additional risks or alternatively, significantlyincrease the exposure to one or more of the present risk factors which mayadversely affect our future operational and financial conditions.

 

***We may not be able to realize the anticipated benefits of acquisitionsand dispositions***

 

The price wepay for the purchase of any material properties is based on engineering andeconomic estimates of the reserves made by management and independent engineersmodified to reflect our technical and economic views. These assessments includea number of material factors and assumptions. Consequently, the reserves acquired may be less than expected, whichcould adversely impact cash flow from operating activities and distributions toUnitholders.  See “ARC Energy Trust —General Development of the Business”.

 

We makeacquisitions and dispositions of businesses and assets in the ordinary courseof business.  Achieving the benefits ofacquisitions depends in part on successfully consolidating functions andintegrating operations and procedures in a timely and efficient manner as wellas our ability to realize the anticipated growth opportunities and synergiesfrom combining the acquired businesses and operations with those of theTrust.  There is no assurance that wewill be able to continue to complete acquisitions or dispositions of oil andnatural gas properties which realize all the synergistic benefits.

 

***The Trust has the authority to impose restrictions on the issuance ofTrust Units to, or the transfer by any Unitholder, of Trust Units to anon-resident***

 

The Trustintends to comply with the requirements under the *Tax Act* for “unit trusts” and “mutual fund trusts” at allrelevant times such that we maintain our status of a unit trust and a mutualfund trust for purposes of the *Tax Act*.  In this regard, we may, from time to time,among other things, take all necessary steps to monitor the activities of theTrust and ownership of the Trust Units. If at any time we become aware that the activities of the Trust andownership of the Trust Units by non-residents (non-residents of Canada andpartnerships) may threaten the status of the Trust under the *Tax Act* as a “unit trust” or “mutual fundtrust”, we are authorized to take such action as may be necessary in theopinion of ARC Resources to maintain the status of the Trust as a unit trustand a mutual fund trust,

 

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including theimposition of restrictions on the issuance by the Trust, or the transfer by anyUnitholder, of Trust Units to a non resident. See “Limitations on Non-ResidentOwnership”.

 

***Climate change laws and related environment regulation may imposerestrictions or impose costs on our business which may adversely effect ourfinancial condition and our ability to maintain distributions***

 

The oil andnatural gas industry is subject to environmental regulation pursuant to local,provincial and federal legislation.  Abreach of such legislation may result in the imposition of fines or issuance ofclean up orders in respect of us or our properties, some of which may bematerial.  Furthermore, managementbelieves the political climate appears to favour new programs for environmentallaws and regulation, particularly in relation to the reduction of emissions oremissions intensity, and there is no assurance that any such programs, laws orregulations, if proposed and enacted, will not contain emission reductiontargets which we cannot meet, and financial penalties or charges could beincurred as a result of the failure to meet such targets.  For more information on the evolution andstatus of climate change and related environmental legislation, see “IndustryConditions — Climate Change Regulation”.

 

There has beenmuch public debate with respect to the Government’s strategy or alternativestrategies with respect to climate change and the control of greenhousegases.  Implementation of strategies byeither the provinces in which we operate our business or by the Government ofCanada, and whether to meet international agreed limits, or as otherwisedetermined, for reducing greenhouse gases could have a material impact on thenature of oil and natural gas operations, including ours.  Given the evolving nature of the debaterelated to climate change and the control of greenhouse gases and resultingrequirements, it is not possible to predict either the nature of thoserequirements or the impact on us and our operations and financialcondition.  Although we have establisheda reclamation fund for the purpose of funding our currently estimated futureenvironmental and reclamation obligations, there can be no assurance that wewill be able to satisfy our actual future environmental and reclamationobligations from such funds.

 

Although webelieve that we are in material compliance with current applicableenvironmental regulations, no assurance can be given that environmental lawswill not result in a curtailment of production or a material increase in thecosts of production, development or exploration activities or otherwiseadversely affect our financial condition, results of operations orprospects.  Future changes in otherenvironmental legislation could occur and result in stricter standards andenforcement, larger fines and liability, and increased capital expenditures andoperating costs, which could have a material adverse effect on our financialcondition or results of operations and prospects.  See “Industry Conditions — Climate ChangeRegulation”.

 

***There is strong competition relating to all aspects of the oil and gasindustry***

 

There arenumerous trusts and corporations in the oil and gas industry, who are competingwith us for the acquisitions of properties with longer life reserves,properties with exploitation and development opportunities and undevelopedland.  As a result of such competition,it may be more difficult for us to acquire reserves on beneficial terms.  Many of these other oil and gas companieshave significantly greater financial and other resources than we do.

 

The Trustcompetes with other oil and gas entities to hire and retain skilled personnelnecessary for the daily operations of the Trust including planning, realizingon available technical advances and the execution of the annual capitaldevelopment program.  The inability tohire and retain skilled personnel could adversely impact certain of ouroperational and financial results.

 

***Application of GAAP or US GAAP to our financial results may result in non-cashlosses which may adversely affect the market price of our Trust Units***

 

CanadianGenerally Accepted Accounting Principles (“**GAAP**”)require that management apply certain accounting policies and make certainestimates and assumptions which affect reported amounts in our consolidatedfinancial statements.  The accountingpolicies may result in non-cash charges to net income and write-downs of netassets in the financial statements. Such non-cash charges and write-downs maybe viewed unfavourably by the market and may result in an inability to borrowfunds and/or may result in a decline in the Trust Unit price.

 

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Under GAAP,the net amounts at which petroleum and natural gas costs on a property orproject basis are carried are subject to a cost-recovery test which is based inpart upon estimated future net revenues from reserves. If net capitalized costsexceed the estimated recoverable amounts, we will have to charge the amounts ofthe excess to earnings.  A decline in thenet value of oil and natural gas properties could cause capitalized costs toexceed the cost ceiling, resulting in a charge against earnings.  The net value of oil and gas properties arehighly dependent upon the prices of oil and natural gas.

 

Under US GAAP,companies using the full cost method of accounting for oil and gas producingactivities perform a ceiling test on each cost centre using discountedestimated future net revenue from proved oil and gas reserves using a discountrate of 10 per cent.  Prices used in theUS GAAP ceiling tests are 12 month average prices, as at December 31,2009.  For the year ended 2009, a ceilingtest write-down of $145 millionwas recorded for US GAAP purposes ($1.15 billion in 2008).  For further information, see Note 24 of ouraudited consolidated financial statements for the year ended December 31,2009 which is incorporated by reference in this Annual Information Form andwhich has been filed on SEDAR at www.sedar.com.

 

Under GAAP,the accounting for derivatives may result in non-cash charges against netincome as a result of changes in the fair market value of derivativeinstruments. A decrease in the fair market value of the derivative instrumentsas the result of fluctuations in commodity prices and foreign exchange ratesmay result in a write-down of net assets and a non-cash charge against netincome. Such write-downs and non-cash charges may be temporary in nature if thefair market value subsequently increases.

 

***Our success depends in large measure on certain key personnel and ourability to retain our key personnel***

 

The loss ofsuch key personnel could delay the completion of certain projects or otherwisehave a material adverse effect on us. Unitholders will be dependent on our management in respect of theadministration and management of all matters relating to our properties, theRoyalties and Trust Units and the safekeeping of our primary workspace andcomputer systems.  As of December 31,2009, we operated approximately 79 percent of the total daily production of our properties.

 

***Our oil and natural gas reserves are a depleting resource and declineas such reserves are produced***

 

Distributionsof distributable income in respect of properties, absent commodity priceincreases or cost effective acquisition and development activities, willdecline over time in a manner consistent with declining production from typicaloil, natural gas and natural gas liquids reserves.  Our future oil and natural gas reserves andproduction, and therefore our cash flows from operating activities, will behighly dependent on our success in exploiting our reserves base and acquiringadditional reserves. Without reserves additions through acquisition ordevelopment activities, our reserves and production may decline over time asreserves are produced.  There can beno assurance that we will be successful in developing or acquiring additionalreserves on terms that meet our investment objectives.

 

***Securing and maintaining title to our properties issubject to certain risks***

 

Ourproperties are held in the form of licenses and leases and working interests inlicenses and leases.  If we or the holderof the license or lease fails to meet the specific requirement of a license orlease, the license or lease may terminate or expire.  There can be no assurance that any of theobligations required to maintain each license or lease will be met.  The termination or expiration of a license orlease or the working interest relating to a license or lease may have amaterial adverse affect on our results of operations and business.  In addition title to the properties canbecome subject to dispute and defeat our claim to title over certain of ourproperties.

 

Aboriginalpeoples have claimed aboriginal title and rights to portions of westernCanada.  We are not aware that anymaterial claims have been made in respect of our properties and assets;however, if a claim arose and was successful this could have an adverse effecton us and our operations.

 

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**Risk Relating to Our Structure and Ownership of Trust Units**

 

***Distributions do not represent a “yield” and are not comparable to debtinstruments and rights of redemption have limited liquidity***

 

Trust Unitswill have no value when reserves from the properties can no longer beeconomically produced and, as a result, distributions do not represent a “yield”in the traditional sense and are not comparable to bonds or other fixed yieldsecurities, where investors are entitled to a full return of the principalamount of debt on maturity in addition to a return on investment throughinterest payments.  Distributionsrepresent a blend of return of Unitholders initial investment and a return onUnitholders initial investment.

 

Unitholdershave a limited right to require a repurchase of their Trust Units, which isreferred to as a redemption right.  It isanticipated that the redemption right will not be the primary mechanism forUnitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject tomaterial limitations.  Any securitieswhich may be distributed *in specie*to Unitholders in connection with a redemption may not be listed on any stockexchange and a market may not develop for such securities and such securitiesmay be illiquid.  In addition, there maybe resale restrictions imposed by law upon the recipients of the securitiespursuant to the redemption right.  See “OurInformation — Right of Redemption.”

 

***The Trust Units do not represent a traditional investment in the oiland natural gas sector and should not be viewed by investors as shares in ARCResources***

 

The TrustUnits represent a fractional interest in the Trust.  Corporate law does not govern the Trust andthe rights of Unitholders.  As holders ofTrust Units, Unitholders will not have the statutory rights normally associatedwith ownership of shares of a corporation including, for example, the right tobring oppression or derivative actions. The rights of Unitholders are specifically set forth in the TrustIndenture.  In addition, trusts are notdefined as recognized entities within the definitions of legislation such asthe *Bankruptcy and Insolvency Act*(Canada), the *Companies’ CreditorsArrangement Act* (Canada) and in some cases the *Winding Up and Restructuring Act*(Canada).  As a result, in the event ofan insolvency or restructuring, a Unitholder’s position as such may be quitedifferent than that of a shareholder of a corporation.  The Trust’s sole assets will be the royaltyand other investments in securities. The price per Trust Unit is a function ofanticipated distributable income, the properties acquired by us and our abilityto effect long-term growth in our value. The market price of the Trust Units will be sensitive to a variety ofmarket conditions including, but not limited to, interest rates and our abilityto acquire suitable oil and natural gas properties. Changes in marketconditions may adversely affect the trading price of the Trust Units.

 

**The Trust Units are not “deposits” within the meaning of the *Canada Deposit Insurance Corporation Act*(Canada) and are not insured under the provisions of that Act or any otherlegislation.  Furthermore, we are not atrust company and, accordingly, are not registered under any trust and loancompany legislation as we do not carry on or intend to carry on the business ofa trust company.**

 

***Unitholder limited liability is subject to contractual and statutoryassurances which may have some enforcement risks***

 

The TrustIndenture provides that no Unitholder will be subject to any liability inconnection with us or our obligations and affairs and, in the event that acourt determines Unitholders are subject to any such liabilities, theliabilities will be enforceable only against, and will be satisfied only out ofour assets. Pursuant to the Trust Indenture, we will indemnify and holdharmless each Unitholder from any costs, damages, liabilities, expenses,charges and losses suffered by a Unitholder resulting from or arising out ofsuch Unitholder not having such limited liability.

 

The TrustIndenture provides that all written instruments signed by or on behalf of theTrust must contain a provision to the effect that such obligation will not bebinding upon Unitholders personally. The principal investment of the Trust isthe royalty agreements which contain such provisions.  Personal liability may also arise in respectof claims against the Trust that do not arise under contracts, including claimsin tort, claims for taxes and possibly certain other statutoryliabilities.  The possibility of anypersonal liability of this nature arising is considered unlikely.  The *IncomeTrusts Liability Act* (Alberta) came into force on July 1,2004.  The legislation

 

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provides thata Unitholder will not be, as a beneficiary, liable for any act, default,obligation or liability of the trustee that arises after the legislation cameinto force.

 

Our operationswill be conducted, upon the advice of counsel, in such a way and in suchjurisdictions as to avoid as far as possible any material risk of liability onUnitholders for claims against the Trust.

 

**Risk Factors Applicable to Residents of the UnitedStates and Other Non-Residents of Canada**

 

***There is limited liability of residents in the United States to enforcecivil remedies***

 

Both ARC andARC Resources are organized under the laws of Alberta, Canada and have theirprincipal place of business in Canada. Most of our directors and all of our officers and the representatives ofthe experts who provide services to us (such as our auditors and ourindependent reserve engineers), and all of our assets and all or a substantialportion of the assets of such persons are located outside the United States.  As a result, it may be difficult forinvestors in the United States to effect service of process within the UnitedStates upon such directors, officers and representatives of experts who are notresidents of the United States or to enforce against them judgements of theUnited States courts based upon civil liability under the United States federalsecurities laws or the securities laws of any state within the UnitedStates.  There is doubt as to theenforceability in Canada against ARC or ARC Resources or against any of ourdirectors, officers or representatives of experts who are not residents of theUnited States, in original actions or in actions for enforcement of judgementsof United States courts of liabilities based solely upon the United Statesfederal securities laws or securities laws of any state within the UnitedStates.

 

***There are differences in reporting practices in Canada and the UnitedStates***

 

We report ourproduction and reserve quantities in accordance with Canadian practices andspecifically in accordance with NI 51-101. These practices are different from the practices used to reportproduction and to estimate reserves in reports and other materials filed withthe Securities Exchange Commission by companies in the United States.

 

We incorporateadditional information with respect to production and reserves which is eithernot generally included or prohibited under rules of the SecuritiesExchange Commission and practices in the United States.  We follow the Canadian practice of reportinggross production and reserve volumes (before deduction of Crown and otherroyalties); however, we also follow the United States practice of separatelyreporting reserve volumes on a net basis (after the deduction of royalties andsimilar payments).  We also follow theCanadian practice of using forecast prices and costs when we estimate ourreserves; whereas the Securities Exchange Commission requires that prices andcosts be averaged for the 12 months as of the date of the reserve report.

 

We included inthis Annual Information Form estimates of proved and proved plus probablereserves.  Probable reserves are higherrisk and are generally believed to be less likely to be accurately estimated orrecovered than proved reserves. The Securities Exchange Commission generallyprohibits the inclusion of estimates of probable reserves in filings made withit.  This prohibition does not apply tous because we are a Canadian foreign private issuer.

 

As aconsequence of the foregoing, our reserve estimates and production volumes inthis Annual Information Form may not be comparable to those made bycompanies utilizing United States reporting and disclosure standards.

 

***There is additional taxation applicable to non-residents***

 

The *Tax Act* and the tax treaties betweenCanada and other countries may impose additional withholding or other taxes onthe distributions or other property paid by us to Unitholders who arenon-residents of Canada, and these taxes may change from time to time.  Since January 1, 2005, a 15 per centCanadian withholding tax is applied to the return of capital portion ofdistributions made to non-resident Unitholders.

 

Additionally,the reduced “Qualified Dividend” rate of 15 per cent tax applied to ourdistributions under current U.S. tax laws is scheduled to expire at the end of2010 and there is no assurance that this reduced tax rate will be renewed bythe U.S. government at such time.

 

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Furthermore,it is anticipated that the implementation of the SIFT tax may have tax consequencesfor non-residents of Canada that are more adverse than the tax consequences toother classes of Unitholders.

 

***There is a foreign exchange risk of non-resident Unitholders***

 

Ourdistributions are declared in Canadian dollars and converted to foreigndenominated currencies at the spot exchange rate at the time of payment.  As a consequence, investors are subject toforeign exchange risk.  To the extentthat the Canadian dollar strengthens with respect to their currency, the amountof the distribution will be reduced when converted to their home currency.

 

**TRANSFER AGENTS ANDREGISTRARS**

 

The transferagent and registrar for the Trust Units and the Exchangeable Shares isComputershare Trust Company of Canada at its principal offices in Calgary andToronto.

 

**MATERIAL CONTRACTS**

 

The followingcomprises particulars of every material contract to the Trust that was enteredinto within the most recently completed financial year, or entered into beforethe most recently completed financial year which is still in effect, other thana contract entered into in the ordinary course of business:

 

1.             TrustIndenture.  For information, see “OurInformation” and “Corporate Governance”.

 

2.             ExchangeableShare Provisions.  For information, see“Share Capital of ARC Resources — Exchangeable Shares”.

 

3.             ExchangeableShare Voting and Exchange Trust Agreement dated January 31, 2001 among thetrust, 908563 Alberta Ltd. (a predecessor to ARC Subco) ARC Resources andComputershare Trust Company of Canada, as amended.  For information, see “Share Capital of ARCResources — Exchangeable Shares”.

 

4.             ExchangeableShare Support Agreement dated January 31, 2001 among the trust, 908563Alberta Ltd. (a predecessor to ARC Subco) ARC Resources and Computershare TrustCompany of Canada, as amended.  Forinformation, see “Share Capital of ARC Resources — Exchangeable Shares”.

 

5.             Amendedand Restated Credit Agreement dated as of March 24, 2006 between ARCResources and a syndicate of lenders, and an administrative agent as amended onApril 15, 2008 for an extendible revolving credit facility up to Cdn $800million.  For information, see “OtherInformation Relating to Our Business - Borrowings”.

 

6.             Amendedand Restated Uncommitted Master Shelf Agreement as of December 15, 2005between ARC Resources and various purchasers for an aggregate principal amountof US $225 million.  For information, see“Other Information Relating to Our Business - Borrowings”.

 

7.             NoteAgreement as of April 27, 2004 between ARC Resources and variouspurchasers for US $62.5 million 4.62 per cent Senior Secured Notes — Series Adue April 27, 2014 and US $62.5 million 5.10 per cent Senior Secured Notes— Series B due April 27, 2016. For information, see “Other Information Relating to Our Business-Borrowings”.

 

8.             NoteAgreement as of April 14, 2009 between ARC Resources and variouspurchasers for US $67.5 million 7.19 per cent Senior Secured Notes — Series Cdue April 14, 2016, US $35 million 8.21 per cent Senior Secured Notes — Series Ddue April 14, 2021 and Cdn $29 million 6.50 per cent Senior Secured Notes— Series E due April 14, 2021. For information, see “Other Information Relating to Our Business —Borrowings”.

 

Copies of eachof these documents have been filed on SEDAR at www.sedar.com.

 

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**INTEREST OF EXPERTS**

 

There is noperson or company whose profession or business gives authority to a statementmade by such person or company and who is named as having prepared or certifieda statement, report or valuation described or included in a filing, or referredto in a filing, made under National Instrument 51-102 by us during, or relatedto, our most recently completed financial year other than GLJ, our independentengineering evaluator, and Deloitte & Touche LLP, our auditors.  As at the date hereof the designatedprofessionals of GLJ, as a group, beneficially owned, directly or indirectly,less than one per cent of our outstanding securities, including the securitiesof our associates and affiliates. Deloitte & Touche LLP is the auditor of the Trust and isindependent within the meaning of the Rules of Professional Conduct of theInstitute of Chartered Accountants of Alberta.

 

In addition,none of the aforementioned persons or companies, nor any director, officer or employeeof any of the aforementioned persons or companies, is or is expected to beelected, appointed or employed as a director, officer or employee of ARCResources or of any of our associate or affiliate entities.  Allan R. Twa, the Corporate Secretary of ARCResources, is a partner of Burnet,Duckworth & Palmer LLP, which law firm renderslegal services to us.

 

**ADDITIONAL INFORMATION**

 

Additionalinformation including remuneration and indebtedness of directors and officersof ARC Resources, principal holders of the Trust Units, Exchangeable Shares andrights to purchase Trust Units, is contained in the Information Circular -Proxy Statement of the Trust which relates to the Annual Meeting of Unitholdersto be held on May 18, 2010. Additional financial information is provided in our consolidatedfinancial statements and accompanying management’s discussion and analysis forthe year ended December 31, 2009, which have been filed on SEDAR atwww.sedar.com.

 

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**APPENDIX AFORM 51-101F2**

 

**REPORT ONRESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR**

 

To the board of directors of ARC ResourcesLtd. (the “**Company**”) on behalf ofARC Energy Trust:

 

1.             Wehave prepared an evaluation of the Company’s reserves data as at December 31,2009.  The reserves data are estimates ofproved reserves and probable reserves and related future net revenues as at December 31,2009, estimated using forecast prices and costs.

 

2.             Thereserves data are the responsibility of the Company’s management.  Our responsibility is to express an opinionon the reserves data based on our evaluation.

 

We carried out our evaluation in accordancewith standards set out in the Canadian Oil and Gas Evaluation Handbook (the “**COGE Handbook**”) prepared jointly by theSociety of Petroleum Evaluation Engineers (Calgary Chapter) and the CanadianInstitute of Mining, Metallurgy & Petroleum (Petroleum Society).

 

3.             Those standards requirethat we plan and perform an evaluation to obtain reasonable assurance as towhether the reserves data are free of material misstatement.  An evaluation also includes assessing whetherthe reserves data are in accordance with principles and definitions presentedin the COGE Handbook.

 

4.             Thefollowing table sets forth the estimated future net revenue (before deductionof income taxes) attributed to proved plus probable reserves, estimated usingforecast prices and costs and calculated using a discount rate of 10 per cent,included in the reserves data of the Company evaluated by us for the year endedDecember 31, 2009, and identifies the respective portions thereof that wehave audited, evaluated and reviewed and reported on to the Company’s board ofdirectors:

 
| **Independent  Qualified Reserves** | ** ** | **Description and  Preparation Date of** | ** ** | **Location of  Reserves (Country  or Foreign** | ** ** | **Net Present Value of Future Net Revenue  (before income taxes, 10% discount rate, $millions)** | ** ** |
|-------------------------------------|------------|------------------------------------------|------------|------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| **Evaluator**                       | ** ** | **Evaluation Report**                    | ** ** | **Geographic Area)**                           | ** ** | **Audited**                                                                                      | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
|                                |       |                                     |       |                                           |       |                                                                                             |       |   |   |   |   |   |   |
| GLJ Petroleum Consultants Ltd.      |       | January 18, 2010                    |       | Canada                                         |       | —                                                                                           |       | 5,805 |   | — |   | 5,805 |   |

 

5.             In our opinion, thereserves data respectively evaluated by us have, in all material respects, beendetermined and are in accordance with the COGE Handbook.

 

6.             Wehave no responsibility to update our report referred to in paragraph 4 forevents and circumstances occurring after its preparation date.

 

7.             Becausethe reserves data are based on judgments regarding future events, actualresults will vary and the variations may be material.  However, any variations should be consistentwith the fact that reserves are categorized according to the probability oftheir recovery.

 

Executedas to our report referred to above:

 
| GLJ Petroleum Consultants Ltd.          |   | Dated  February 22, 2010 |
|-----------------------------------------|--------|-------------------------------|
| Calgary, Alberta, Canada                |   |                          |
|                                    |   |                          |
|                                    |   |                          |
| *(signed) “James H. Willmon”* |   |                          |
| James  H. Willmon, P.Eng                |   |                          |
| Vice  President                         |   |                          |

 

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**APPENDIX BFORM 51-101F3**

 

**REPORT OFMANAGEMENT AND DIRECTORS ONRESERVES DATA AND OTHER INFORMATION**

 

Management of ARC Resources Ltd. (the “**Company**”) on behalf of ARC Energy Trust(the “**Trust**”) are responsible forthe preparation and disclosure of information with respect to the Company’s andthe other Trust’s subsidiaries’ oil and gas activities in accordance withsecurities regulatory requirements. This information includes reserves data,which are estimates of proved reserves and probable reserves and related futurenet revenues as at December 31, 2009 estimated using forecast prices andcosts.

 

An independent qualified reserves evaluatorhas evaluated the Company’s and the other Trust’s subsidiaries’ reserves data.The report of the independent qualified reserves evaluator is presented below.

 

The Reserves Committee of the board ofdirectors of the Company has

 

(a)           reviewedthe Company’s procedures for providing information to the independent qualifiedreserves evaluator;

 

(b)           metwith the independent qualified reserves evaluator to determine whether anyrestrictions affected the ability of the independent qualified reservesevaluator to report without reservation; and

 

(c)           reviewedthe reserves data with management and the independent qualified reservesevaluator.

 

The Reserves Committee of the board ofdirectors has reviewed the Company’s procedures for assembling and reportingother information associated with oil and gas activities and has reviewed thatinformation with management. The board of directors has, on the recommendationof the Reserves Committee, approved

 

(d)           thecontent and filing with securities regulatory authorities of Form 51-101F1containing reserves data and other oil and gas information;

 

(e)           thefiling of Form 51-101F2 which is the report of the independent qualifiedreserves evaluator on the reserves data; and

 

(f)            thecontent and filing of this report.

 

Because the reserves data are based onjudgments regarding future events, actual results will vary and the variationsmay be material.  However, any variationsshould be consistent with the fact that reserves are categorized according tothe probability of their recovery.

 
| (signed) “*John  P. Dielwart*”           |   | (signed) “*Myron  Stadnyk*”          |
|----------------------------------------------------|--------|------------------------------------------------|
| John P. Dielwart                                   |   | Myron Stadnyk                                  |
| Chief Executive Officer                            |   | President and Chief Operating Officer          |
|                                               |   |                                           |
|                                               |   |                                           |
| (signed) “*James  Houck*”                |   | (signed) “*Fred  J. Dyment*”         |
| James Houck                                        |   | Fred J. Dyment                                 |
| Director and Chairman****of the Reserves Committee |   | Director and Member of the Reserves  Committee |
|                                               |   |                                           |
|                                               |   |                                           |
| March 16, 2010                                |   |                                           |

 

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**APPENDIX C**

 

**MANDATE OF THE AUDIT COMMITTEE**

 

**Role and Objective**

 

The Audit Committee (the “Committee”) is a committeeof the Board of Directors of ARC Resources Ltd. (“ARL”) to which the Board hasdelegated its responsibility for oversight of the nature and scope of theannual audit, management’s reporting on internal accounting standards andpractices, financial information and accounting systems and procedures,financial reporting and statements and recommending, for Board of Directorapproval, the audited financial statements and other mandatory disclosurereleases containing financial information. The objectives of the Committee, with respect to ARL and ARC EnergyTrust (the “Trust”) (hereinafter collectively referred to as “ARC”), are asfollows:

 

·              To assist Directors to meet their responsibilities in respect of thepreparation and disclosure of the financial statements of ARC and relatedmatters.

 

·              To provide better communication between directors and external auditors.

 

·              To ensure the external auditors’ independence.

 

·              To increase the credibility and objectivity of financial reports.

 

·              To strengthen the role of the outside directors by facilitating in depthdiscussions between directors on the Committee, management and externalauditors.

 

**Mandate and Responsibilitiesof Committee**

 

·              It is the responsibility of the Committee to satisfy itself on behalf ofthe Board with respect to ARC’s internal control systems, including inparticular relating to derivative instruments:

 

·      identifying, monitoring and mitigating businessrisks.

 

·      ensuring compliance with legal and regulatoryrequirements.

 

·              It is a primary responsibility of the Committee to review the annual andquarterly financial statements of ARC prior to their submission to the Board ofDirectors for approval.  The processshould include but not be limited to:

 

·      reviewing changes in accounting principles, or intheir application, which may have a material impact on the current or futureyears’ financial statements;

 

·      reviewing significant accruals, reserves or otherestimates such as the ceiling test calculation;

 

·      reviewing accounting treatment of unusual ornon-recurring transactions;

 

·      reviewing the Trust’s status as a “mutual fundtrust” under the *Income Tax Act*(Canada);

 

·      ascertaining compliance with covenants under loanagreements and Trust Indenture;

 

·      reviewing financial reporting relating to assetretirement obligations;

 

·      reviewing disclosure requirements for commitmentsand contingencies;

 

·      reviewing adjustments raised by the externalauditors, whether or not included in the financial statements;

 

·      reviewing unresolved differences between managementand the external auditors;

 

·      obtain explanations of significant variances withcomparative reporting periods; and

 

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·      determine through inquiry if there are any relatedparty transactions and ensure the nature and extent of such transactions areproperly disclosed.

 

·              The Committee is to review the financial statements and relatedinformation included in prospectuses, management discussion and analysis(MD&A), information circular-proxy statements and annual information forms(AIF), prior to Board approval.

 

·              With respect to the appointment of external auditors by the Board, theCommittee shall:

 

·      be directly responsible for overseeing the work ofthe external auditors engaged for the purpose of issuing an auditors’ report orperforming other audit, review or attest services for the Trust, including theresolution of disagreements between management and the external auditor regardingfinancial reporting;

 

·      review management’s recommendation for theappointment of external auditors and recommend to the Board appointment ofexternal auditors and the compensation of the external auditors;

 

·      review the terms of engagement of the externalauditors, including the appropriateness and reasonableness of the auditors’fees;

 

·      when there is to be a change in auditors, review theissues related to the change and the information to be included in the requirednotice to securities regulators of such change; and

 

·      review and approve any non-audit services to beprovided by the external auditors’ firm and consider the impact on theindependence of the auditors.

 

·              Review with external auditors (and internal auditor if one is appointedby ARC) their assessment of the internal controls of ARC, their written reportscontaining recommendations for improvement, and management’s response andfollow-up to any identified weaknesses.

 

·              The Committee shall also review annually with the external auditorstheir plan for their audit and, upon completion of the audit, their reportsupon the financial statements of ARC and its subsidiaries.

 

·              Review all public disclosure containing audited or unaudited financialinformation before release.

 

·              Review financial reporting relating to risk exposure.

 

·              Satisfy itselfthat adequate procedures are in place for the review of the Trust’s publicdisclosure of financial information from the Trust’s financial statements andperiodically assess the adequacy of those procedures.

 

·              Establish proceduresfor:

 

·      the receipt, retention and treatment of complaintsreceived by the Trust regarding accounting, internal accounting controls, orauditing matters; and

 

·      the confidential, anonymous submission by employeesof the Trust of concerns regarding questionable accounting or auditing matters.

 

·              Review and approve ARC’s hiring policies regarding partners, employeesand former partners and employees of the present and external auditors of ARC.

 

·              Review any other matters that the Audit Committee feels are important toits mandate or that the Board chooses to delegate to it.

 

·              Undertake annually a review of this mandate and make recommendations tothe Policy and Board Governance Committee as to proposed changes.

 

C-2

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**Composition**

 

·              This Committee shall be composed of at least three individuals appointedby the Board from amongst its members, all of which members will be independent(within the meaning of Multilateral Instrument 52-110 Audit Committees) unlessthe Board determines to rely on an exemption in NI 52-110.  “Independent” generally means free from anybusiness or other direct or indirect material relationship with ARC that could,in the view of the Board of Directors, reasonably interfere with the exerciseof the member’s independent judgment.

 

·              The Secretary to the Board shall act as Secretary of the Committee.

 

·              A quorum shall be a majority of the members of the Committee.

 

·              All of the members must be financially literate within the meaning of NI52-110 unless the Board has determined to rely on an exemption in NI52-110.  Being “financially literate”means members have the ability to read and understand a set of financialstatements that present a breadth and level of complexity of accounting issuesthat are generally comparable to the breadth and complexity of issues that canreasonably be expected to be raised by the Trust’s financial statements.

 

**Meetings**

 

·              The Committee shall meet at least four times per year and/or as deemedappropriate by the Committee Chair.

 

·              The Committee shall meet not less than quarterly with the auditors,independent of the presence of management.

 

·              Agendas, with input from management, shall be circulated to Committeemembers and relevant management personnel along with background information ona timely basis prior to the Committee meetings.

 

·              Minutes of each meeting shall be prepared by the Secretary to theCommittee.

 

·              The Chief Executive Officer and the Chief Financial Officer or theirdesignates shall be available to attend at all meetings of the Committee uponthe invitation of the Committee.

 

·              The Controller, Treasurer and such other staff as appropriate to provideinformation to the Committee shall attend meetings upon invitation by theCommittee.

 

**Reporting / Authority**

 

·              Following each meeting, in addition to a verbal report, the Committeewill report to the Board by way of providing copies of the minutes of suchCommittee meeting at the next Board meeting after a meeting is held (these maystill be in draft form).

 

·              Supporting schedules and information reviewed by the Committee shall beavailable for examination by any director.

 

·              TheCommittee shall have the authority to investigate any financial activity of theCorporation and to communicate directly with the internal and externalauditors.  All employees are to cooperateas requested by the Committee.

 

·              TheCommittee may retain, and set and pay the compensation for, persons havingspecial expertise and/or obtain independent professional advice to assist infulfilling its duties and responsibilities at the expense of ARC.

 

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